`[Federal Register Volume 77, Number 32 (Thursday, February 16, 2012)]
[Rules and Regulations]
[Pages 9304-9513]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2012-806]



[[Page 9303]]

Vol. 77

Thursday,

No. 32

February 16, 2012

Part II





Environmental Protection Agency





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40 CFR Parts 60 and 63





National Emission Standards for Hazardous Air Pollutants From Coal- and 
Oil-Fired Electric Utility Steam Generating Units and Standards of 
Performance for Fossil-Fuel-Fired Electric Utility, Industrial-
Commercial-Institutional, and Small Industrial-Commercial-Institutional 
Steam Generating Units; Final Rule

  Federal Register / Vol. 77 , No. 32 / Thursday, February 16, 2012 / 
Rules and Regulations  

[[Page 9304]]


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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Parts 60 and 63

[EPA-HQ-OAR-2009-0234; EPA-HQ-OAR-2011-0044, FRL-9611-4]
RIN 2060-AP52; RIN 2060-AR31


National Emission Standards for Hazardous Air Pollutants From 
Coal- and Oil-Fired Electric Utility Steam Generating Units and 
Standards of Performance for Fossil-Fuel-Fired Electric Utility, 
Industrial-Commercial-Institutional, and Small Industrial-Commercial-
Institutional Steam Generating Units

AGENCY: Environmental Protection Agency (EPA).

ACTION: Final rule.

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SUMMARY: On May 3, 2011, under authority of Clean Air Act (CAA) 
sections 111 and 112, the EPA proposed both national emission standards 
for hazardous air pollutants (NESHAP) from coal- and oil-fired electric 
utility steam generating units (EGUs) and standards of performance for 
fossil-fuel-fired electric utility, industrial-commercial-
institutional, and small industrial-commercial-institutional steam 
generating units (76 FR 24976). After consideration of public comments, 
the EPA is finalizing these rules in this action.
    Pursuant to CAA section 111, the EPA is revising standards of 
performance in response to a voluntary remand of a final rule. 
Specifically, we are amending new source performance standards (NSPS) 
after analysis of the public comments we received. We are also 
finalizing several minor amendments, technical clarifications, and 
corrections to existing NSPS provisions for fossil fuel-fired EGUs and 
large and small industrial-commercial-institutional steam generating 
units.
    Pursuant to CAA section 112, the EPA is establishing NESHAP that 
will require coal- and oil-fired EGUs to meet hazardous air pollutant 
(HAP) standards reflecting the application of the maximum achievable 
control technology. This rule protects air quality and promotes public 
health by reducing emissions of the HAP listed in CAA section 
112(b)(1).

DATES: This final rule is effective on April 16, 2012. The 
incorporation by reference of certain publications listed in this rule 
is approved by the Director of the Federal Register as of April 16, 
2012.

ADDRESSES: The EPA established two dockets for this action: Docket ID. 
No. EPA-HQ-OAR-2011-0044 (NSPS action) or Docket ID No. EPA-HQ-OAR-
2009-0234 (NESHAP action). All documents in the dockets are listed on 
the http://www.regulations.gov Web site. Although listed in the index, 
some information is not publicly available, e.g., confidential business 
information or other information whose disclosure is restricted by 
statute. Certain other material, such as copyrighted material, is not 
placed on the Internet and will be publicly available only in hard copy 
form. Publicly available docket materials are available either 
electronically through http://www.regulations.gov or in hard copy at 
EPA's Docket Center, Public Reading Room, EPA West Building, Room 3334, 
1301 Constitution Avenue NW., Washington, DC 20004. This Docket 
Facility is open from 8:30 a.m. to 4:30 p.m., Monday through Friday, 
excluding legal holidays. The telephone number for the Public Reading 
Room is (202) 566-1744, and the telephone number for the Air Docket is 
(202) 566-1741.

FOR FURTHER INFORMATION CONTACT: For the NESHAP action: Mr. William 
Maxwell, Energy Strategies Group, Sector Policies and Programs 
Division, (D243-01), Office of Air Quality Planning and Standards, U.S. 
Environmental Protection Agency, Research Triangle Park, North Carolina 
27711; Telephone number: (919) 541-5430; Fax number (919) 541-5450; 
Email address: [email protected]. For the NSPS action: Mr. Christian 
Fellner, Energy Strategies Group, Sector Policies and Programs 
Division, (D243-01), Office of Air Quality Planning and Standards, U.S. 
Environmental Protection Agency, Research Triangle Park, North Carolina 
27711; Telephone number: (919) 541-4003; Fax number (919) 541-5450; 
Email address: [email protected].

SUPPLEMENTARY INFORMATION: 
    The information presented in this preamble is organized as follows:

I. General Information
    A. Does this action apply to me?
    B. Where can I get a copy of this document?
    C. Judicial Review
    D. What are the costs and benefits of these final rules?
II. Background Information on the NESHAP
    A. What is the statutory authority for this final NESHAP?
    B. What is the litigation history of this final rule?
    C. What is the relationship between this final rule and other 
combustion rules?
    D. What are the health effects of pollutants emitted from coal- 
and oil-fired EGUs?
III. Appropriate and Necessary Finding
    A. Overview
    B. Peer Review of the Hg Risk TSD Supporting the Appropriate and 
Necessary Finding for Coal and Oil-Fired EGUs and EPA Response
    C. Summary of Results of Revised Hg Risk TSD of Risks to 
Populations With High Levels of Self-Caught Fish Consumption
    D. Peer Review of the Approach for Estimating Cancer Risks 
Associated With Cr and Ni Emissions in the U.S. EGU Case Studies of 
Cancer and Non-Cancer Inhalation Risks for Non-Mercury Hg HAP and 
EPA Response
    E. Summary of Results of Revised U.S. EGU Case Studies of Cancer 
and Non-Cancer Inhalation Risks for Non-Mercury Hg HAP
    F. Public Comments and Responses to the Appropriate and 
Necessary Finding
    G. EPA Affirms the Finding That It Is Appropriate and Necessary 
To Regulate EGUs To Address Public Health and Environmental Hazards 
Associated With Emissions of Hg and Non-Mercury Hg HAP From EGUs
IV. Denial of Delisting Petition
    A. Requirements of Section 112(c)(9)
    B. Rationale for Denying UARG's Delisting Petition
    C. EPA's Technical Analyses for the Appropriate and Necessary 
Finding Provide Further Support for the Conclusion That Coal-Fired 
EGUs Should Remain a Listed Source Category
V. Summary of the Final NESHAP
    A. What is the source category regulated by this final rule?
    B. What is the affected source?
    C. What are the pollutants regulated by this final rule?
    D. What emission limits and work practice standards must I meet?
    E. What are the requirements during periods of startup, 
shutdown, and malfunction?
    F. What are the testing and initial compliance requirements?
    G. What are the continuous compliance requirements?
    H. What are the notification, recordkeeping and reporting 
requirements?
    I. Submission of Emissions Test Results to the EPA
VI. Summary of Significant Changes Since Proposal
    A. Applicability
    B. Subcategories
    C. Emission Limits
    D. Work Practice Standards for Organic HAP Emissions
    E. Requirements During Startup, Shutdown, and Malfunction
    F. Testing and Initial Compliance
    G. Continuous Compliance
    H. Emissions Averaging
    I. Notification, Recordkeeping and Reporting
    J. Technical/Editorial Corrections
VII. Public Comments and Responses to the Proposed NESHAP
    A. MACT Floor Analysis
    B. Rationale for Subcategories
    C. Surrogacy
    D. Area Sources
    E. Health-Based Emission Limits
    F. Compliance Date and Reliability Issues

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    G. Cost and Technology Basis Issues
    H. Testing and Monitoring
VIII. Background Information on the NSPS
    A. What is the statutory authority for this final NSPS?
    B. What is the regulatory authority for the final rule?
IX. Summary of the Final NSPS
X. Summary of Significant Changes Since Proposal
XI. Public Comments and Responses to the Proposed NSPS
XII. Impacts of the Final Rule
    A. What are the air impacts?
    B. What are the energy impacts?
    C. What are the cost impacts?
    D. What are the economic impacts?
    E. What are the benefits of this final rule?
XIII. Statutory and Executive Order Reviews
    A. Executive Order 12866, Regulatory Planning and Review and 
Executive Order 13563, Improving Regulation and Regulatory Review
    B. Paperwork Reduction Act
    C. Regulatory Flexibility Act as Amended by the Small Business 
Regulatory Enforcement Fairness Act (RFA) of 1996 SBREFA), 5 U.S.C. 
601 et seq.
    D. Unfunded Mandates Reform Act of 1995
    E. Executive Order 13132, Federalism
    F. Executive Order 13175, Consultation and Coordination With 
Indian Tribal Governments
    G. Executive Order 13045, Protection of Children From 
Environmental Health Risks and Safety Risks
    H. Executive Order 13211, Actions Concerning Regulations That 
Significantly Affect Energy Supply, Distribution, or Use
    I. National Technology Transfer and Advancement Act
    J. Executive Order 12898: Federal Actions To Address 
Environmental Justice in Minority Populations and Low-Income 
Populations
    K. Congressional Review Act

I. General Information

A. Does this action apply to me?

    The regulated categories and entities potentially affected by the 
final standards are shown in Table 1 of this preamble.

     Table 1--Potentially Affected Regulated Categories and Entities
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                                                         Examples of
             Category                NAICS code 1        potentially
                                                      regulated entities
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Industry.........................            221112  Fossil fuel-fired
                                                      electric utility
                                                      steam generating
                                                      units.
Federal government...............          2 221122  Fossil fuel-fired
                                                      electric utility
                                                      steam generating
                                                      units owned by the
                                                      federal
                                                      government.
State/local/tribal government....          2 221122  Fossil fuel-fired
                                                      electric utility
                                                      steam generating
                                                      units owned by
                                                      states, tribes, or
                                                      municipalities.
                                             921150  Fossil fuel-fired
                                                      electric utility
                                                      steam generating
                                                      units in Indian
                                                      country.
------------------------------------------------------------------------
1 North American Industry Classification System.
2 Federal, state, or local government-owned and operated establishments
  are classified according to the activity in which they are engaged.

    This table is not intended to be exhaustive, but rather is meant to 
provide a guide for readers regarding entities likely to be affected by 
this action. To determine whether you, as owner or operator of a 
facility, company, business, organization, etc., will be regulated by 
this action, you should examine the applicability criteria in 40 CFR 
60.40, 60.40Da, or 60.40c or in 40 CFR 63.9981. If you have any 
questions regarding the applicability of this action to a particular 
entity, consult either the air permitting authority for the entity or 
your EPA regional representative as listed in 40 CFR 60.4 or 40 CFR 
63.13 (General Provisions).

B. Where can I get a copy of this document?

    In addition to being available in the dockets, an electronic copy 
of this action will also be available on the Worldwide Web (WWW) 
through the Technology Transfer Network (TTN). Following signature by 
the Administrator, a copy of the action will be posted on the TTN's 
policy and guidance page for newly proposed or promulgated rules at the 
following address: http://www.epa.gov/ttn/oarpg/. The TTN provides 
information and technology exchange in various areas of air pollution 
control.

C. Judicial Review

    Under CAA section 307(b)(1), judicial review of this final rule is 
available only by filing a petition for review in the U.S. Court of 
Appeals for the District of Columbia Circuit by April 16, 2012. Under 
CAA section 307(d)(7)(B), only an objection to this final rule that was 
raised with reasonable specificity during the period for public comment 
(including any public hearing) can be raised during judicial review. 
This section also provides a mechanism for the EPA to convene a 
proceeding for reconsideration, ``[i]f the person raising an objection 
can demonstrate to the Administrator that it was impracticable to raise 
such objection within [the period for public comment] or if the grounds 
for such objection arose after the period for public comment (but 
within the time specified for judicial review) and if such objection is 
of central relevance to the outcome of the rule[.]'' Any person seeking 
to make such a demonstration to us should submit a Petition for 
Reconsideration to the Office of the Administrator, Environmental 
Protection Agency, Room 3000, Ariel Rios Building, 1200 Pennsylvania 
Ave. NW., Washington, DC 20004, with a copy to the person listed in the 
preceding FOR FURTHER INFORMATION CONTACT section, and the Associate 
General Counsel for the Air and Radiation Law Office, Office of General 
Counsel (Mail Code 2344A), Environmental Protection Agency, 1200 
Pennsylvania Ave. NW., Washington, DC 20004. Note, under CAA section 
307(b)(2), the requirements established by this final rule may not be 
challenged separately in any civil or criminal proceedings brought by 
EPA to enforce these requirements.

D. What are the costs and benefits of this final rule?

    Consistent with Executive Order (EO) 13563, ``Improving Regulation 
and Regulatory Review,'' we have estimated the costs and benefits of 
the final rule. This rule will reduce emissions of HAP, including 
mercury (Hg), from the electric power industry. Installing the 
technology necessary to reduce emissions directly regulated by this 
rule will also reduce the emissions of directly emitted 
PM2.5 and sulfur dioxide (SO2), a 
PM2.5 precursor. The benefits associated with these PM and 
SO2 reductions are referred to as co-benefits, as these 
reductions are not the primary objective of this rule.
    The EPA estimates that this final rule will yield annual monetized 
benefits (in 2007$) of between $37 to $90 billion using a 3 percent 
discount rate and $33 to $81 billion using a 7 percent discount rate. 
The great majority of the estimates are attributable to co-benefits 
from reductions in PM2.5-related mortality. The annual 
social costs, approximated

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by the sum of the compliance costs and monitoring and reporting costs, 
are $9.6 billion (2007$) and the annual quantified net benefits (the 
difference between benefits and costs) are $27 to $80 billion using a 3 
percent discount rate or $24 to $71 billion using a 7 percent discount 
rate. It is important to note that the PM2.5 co-benefits 
reported here contain uncertainty, due in part to the important 
assumption that all fine particles are equally potent in causing 
premature mortality and because many of the benefits are associated 
with reducing PM2.5 levels at the low end of the 
concentration distributions examined in the epidemiology studies from 
which the PM2.5-mortality relationships used in this 
analysis are derived.
    The benefits of this rule outweigh costs by between 3 to 1 or 9 to 
1 depending on the benefit estimate and discount rate used. The co-
benefits are substantially attributable to the 4,200 to 11,000 fewer 
PM2.5-related premature mortalities estimated to occur as a 
result of this rule. The EPA could not monetize some costs and 
important benefits, such as some Hg benefits and those for the HAP 
reduced by this final rule other than Hg. Upon considering these 
limitations and uncertainties, it remains clear that the benefits of 
this rule, referred to in short as the Mercury and Air Toxics Standards 
(MATS), are substantial and far outweigh the costs.

      Table 2--Summary of the Monetized Benefits, Social Costs, and Net Benefits for the Final Rule in 2016
                                             [Billions of 2007$] \a\
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                                              3% Discount rate                        7% Discount rate
----------------------------------------------------------------------------------------------------------------
Total Monetized Benefits \b\.....  $37 to $90............................  $33 to $81.
Partial Hg-related Benefits \c\..  $0.004 to $0.006......................  $0.0005 to $0.001.
PM2.5-related Co-benefits \b\....  $36 to $89............................  $33 to $80.
Climate-related Co-Benefits \d\..  $0.36.................................  $0.36.
Total Social Costs \e\...........  $9.6..................................  $9.6.
Net Benefits.....................  $27 to $80............................  $24 to $71.
Non-monetized Benefits...........                           Visibility in Class I areas.
                                                     Other neurological effects of Hg exposure.
                                                        Other health effects of Hg exposure.
                                            Health effects of ozone and direct exposure to SO2 and NO2.
                                                                 Ecosystem effects.
                                        Health effects from commercial and non-freshwater fish consumption.
                                                   Health risks from exposure to non-mercury HAP.
----------------------------------------------------------------------------------------------------------------
\a\ All estimates are for 2016, and are rounded to two significant figures.
\b\ The total monetized benefits reflect the human health benefits associated with reducing exposure to PM2.5.
  The reduction in premature fatalities each year accounts for over 90 percent of total monetized benefits.
  Benefits in this table are nationwide and are associated with directly emitted PM2.5 and SO2 reductions. The
  estimate of social benefits also includes CO2-related benefits calculated using the social cost of carbon,
  discussed further in chapter 5 of the RIA. Mercury benefits were calculated using the baseline from proposal.
  The difference in emissions reductions between proposal and final does not substantially affect the Hg
  benefits.
\c\ Based on an analysis of health effects due to recreational freshwater fish consumption.
\d\ This table shows monetized CO2 co-benefits that were calculated using the global average social cost of
  carbon estimate at a 3 percent discount rate. In section 5.6 of the Regulatory Impact Analysis (RIA) we also
  report the monetized CO2 co-benefits using discount rates of 5 percent, 2.5 percent, and 3 percent (95th
  percentile).
\e\ Total social costs are approximated by the compliance costs for both coal- and oil-fired units. This
  includes monitoring, recordkeeping, and reporting costs.

    For more information on how EPA is addressing EO 13563, see the EO 
discussion in the Statutory and Executive Order Reviews section of this 
preamble.

II. Background Information on the NESHAP

    On May 3, 2011, the EPA proposed this rule to address emissions of 
toxic air pollutants from coal and oil-fired electric generating units 
as required by the CAA. The proposal explained at length the statutory 
history and requirements leading to this rule, the factual and legal 
basis for the rule and its specific provisions, and the costs and 
benefits to the public health and environment from the proposed 
requirements.
    The EPA received over 900,000 comments from members of the public 
on the proposed rule, substantially more than for any other prior 
regulatory proposal. The comments express concerns about the presence 
of Hg in the environment and the effect it has on human health, 
concerns about the costs of the rule, how challenging it may be for 
some sources to comply and questions about the impact it may have on 
this country's electricity supply and economy. Many comments provided 
additional information and data that have enriched the factual record 
and enabled EPA to finalize a rule that fulfills the mandate of the CAA 
while providing flexibility and compliance options to affected 
sources--options that make the rule less costly and compliance more 
readily manageable.
    This rule establishes uniform emissions-control standards that 
sources can meet with proven and available technologies and operational 
processes in a timeframe that is achievable. They will put this 
industry, now the single largest source of Hg emissions in the United 
States (U.S.) with emissions of 29 tons per year, on a path to reducing 
those emissions by approximately 90 percent. Emissions of other toxic 
metals, such as arsenic (As) and nickel (Ni), dioxins and furans, acid 
gases (including hydrochloric acid (HCl) and SO2) will also 
decrease dramatically with the installation of pollution controls. And 
the flexibilities established in this rule along with other available 
tools provide a clear pathway to compliance without jeopardizing the 
country's energy supply.
    This preamble explains EPA's appropriate and necessary finding, the 
elements of the final rule, key changes the EPA is making in response 
to comments submitted on the proposed rule, and our responses to many 
of the comments we received. A full response to comments is provided in 
the response to comments document available in the docket for this 
rulemaking.

[[Page 9307]]

A. What is the statutory authority for this final rule?

    Congress established a specific structure for determining whether 
to regulate EGUs under CAA section 112.\1\ Specifically, Congress 
enacted CAA section 112(n)(1).
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    \1\ ``Electric utility steam generating unit'' is defined, in 
part, as any ``fossil fuel fired combustion unit of more than 25 
megawatts that serves a generator that produces electricity for 
sale.'' See CAA section 112(a)(8).
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    Section 112(n)(1)(A) of the CAA requires the EPA to conduct a study 
to evaluate the remaining public health hazards that are reasonably 
anticipated to occur as a result of EGUs' HAP emissions after 
imposition of CAA requirements. The EPA must report the results of that 
study to Congress, and regulate EGUs ``if the Administrator finds such 
regulation is appropriate and necessary,'' after considering the 
results of that study. Thus, CAA section 112(n)(1)(A) governs how the 
Administrator decides whether to list EGUs for regulation under CAA 
section 112. See New Jersey v. EPA, 517 F.3d 574 at 582 (D.C. Cir. 
2008) (``Section 112(n)(1) governs how the Administrator decides 
whether to list EGUs; it says nothing about delisting EGUs.'').
    As directed, the EPA conducted the study to evaluate the remaining 
public health hazards and reported the results to Congress (Utility 
Study Report to Congress (Utility Study)).\2\ We discuss this study 
below in conjunction with other studies that CAA section 112(n)(1) 
requires concerning EGUs. See also 76 FR 24982-24984 (summarizing 
studies).
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    \2\ U.S. EPA. Study of Hazardous Air Pollutant Emissions from 
Electric Utility Steam Generating Units--Final Report to Congress. 
EPA-453/R-98-004a. February 1998.
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    Once the EPA lists a source category pursuant to CAA section 
112(c), the EPA must then establish technology-based emission standards 
under CAA section 112(d). For major sources, the EPA must establish 
emission standards that ``require the maximum degree of reduction in 
emissions of the hazardous air pollutants subject to this section'' 
that the EPA determines are achievable taking into account certain 
statutory factors. See CAA section 112(d)(2). These standards are 
referred to as ``maximum achievable control technology'' or ``MACT'' 
standards. The MACT standards for existing sources must be at least as 
stringent as the average emission limitation achieved by the best 
performing 12 percent of existing sources in the category (for which 
the Administrator has emissions information) or the best performing 5 
sources for source categories with less than 30 sources. See CAA 
section 112(d)(3)(A) and (B), respectively. This level of minimum 
stringency is referred to as the ``MACT floor,'' and the EPA cannot 
consider cost in setting the floor. For new sources, MACT standards 
must be at least as stringent as the control level achieved in practice 
by the best controlled similar source. See CAA section 112(d)(3).
    The EPA also must consider more stringent ``beyond-the-floor'' 
control options. When considering beyond-the-floor options, the EPA 
must consider the maximum degree of reduction in HAP emissions and take 
into account costs, energy, and non-air quality health and 
environmental impacts when doing so. See Cement Kiln Recycling Coal. v. 
EPA, 255 F.3d 855, 857-58 (D.C. Cir. 2001).
    Alternatively, the EPA may set a health-based standard for HAP that 
have an established health threshold, and the standard must provide 
``an ample margin of safety.'' See CAA section 112(d)(4). As these 
standards could be less stringent than MACT standards, the Agency must 
have detailed information on HAP emissions from the subject sources and 
sources located near the subject sources before exercising its 
discretion to set such standards.
    For area sources, the EPA may issue standards or requirements that 
provide for the use of generally available control technologies or 
management practices (GACT standards) in lieu of promulgating MACT or 
health-based standards. See CAA section 112(d)(5).
    As noted above, CAA section 112(n) requires completion of various 
reports concerning EGUs. For the first report, the Utility Study, 
Congress required the EPA to evaluate the hazards to public health 
reasonably anticipated to occur as the result of HAP emissions from 
EGUs after imposition of the requirements of the CAA. See CAA section 
112(n)(1)(A). The EPA was required to report results from this study to 
Congress by November 15, 1993. Id. Congress also directed the EPA to 
conduct ``a study of mercury emissions from [EGUs], municipal waste 
combustion units, and other sources, including area sources'' (Mercury 
Study). See CAA section 112(n)(1)(B). The EPA was required to report 
the results from this study to Congress by November 15, 1994. Id. In 
conducting this Mercury Study, Congress directed the EPA to ``consider 
the rate and mass of such emissions, the health and environmental 
effects of such emissions, technologies which are available to control 
such emissions, and the costs of such technologies.'' Id. Congress 
directed the National Institute of Environmental Health Sciences 
(NIEHS) to conduct the last required evaluation, ``a study to determine 
the threshold level of mercury exposure below which adverse human 
health effects are not expected to occur'' (NIEHS Study). See CAA 
section 112(n)(1)(C). The NIEHS was required to submit the results to 
Congress by November 15, 1993. Id. In conducting this study, NIEHS was 
to determine ``a threshold for mercury concentrations in the tissue of 
fish which may be consumed (including consumption by sensitive 
populations) without adverse effects to public health.'' Id.
    In addition, Congress, in conference report language associated 
with the EPA's fiscal year 1999 appropriations, directed the EPA to 
fund the National Academy of Sciences (NAS) to perform an independent 
evaluation of the available data related to the health impacts of 
methylmercury (MeHg) (NAS Study or MeHg Study). H.R. Conf. Rep. No 105-
769, at 281-282 (1998). Specifically, Congress required NAS to advise 
the EPA as to the appropriate reference dose (RfD) for MeHg. 65 FR 
79826. The RfD is the amount of a chemical which, when ingested daily 
over a lifetime, is anticipated to be without adverse health effects to 
humans, including sensitive subpopulations. In the same conference 
report, Congress indicated that the EPA should not make the appropriate 
and necessary regulatory determination for Hg emissions until the EPA 
had reviewed the results of the NAS Study. See H.R. Conf. Rep. No 105-
769, at 281-282 (1998).
    As directed by Congress through different vehicles, the NAS Study 
and the NIEHS Study evaluated the same issues. The NIEHS completed the 
NIEHS Study in 1995,\3\ and the NAS completed the NAS Study in 2000.\4\ 
Because NAS completed its study 5 years after the NIEHS Study, and 
considered additional information not earlier available to NIEHS, for 
purposes of this document we discuss the content of the NAS Study as 
opposed to the NIEHS Study.
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    \3\ NIEHS Study, August 1995; EPA-HQ-OAR-2009-3053.
    \4\ National Research Council (NAS). 2000. Toxicological Effects 
of Methylmercury. Committee on the Toxicological Effects of 
Methylmercury, Board on Environmental Studies and Toxicology, 
National Research Council.
---------------------------------------------------------------------------

    The EPA conducted the studies required by CAA section 112(n)(1) 
concerning utility HAP emissions, the Utility Study and the Mercury 
Study,\5\ and completed both by 1998. Prior to issuance of the Mercury 
Study, the EPA

[[Page 9308]]

engaged in two extensive external peer reviews of the document.
---------------------------------------------------------------------------

    \5\ Mercury Study Report to Congress, December 1997; EPA-HQ-OAR-
2009-0234-3054.
---------------------------------------------------------------------------

    On December 20, 2000, the EPA issued a finding pursuant to CAA 
section 112(n)(1)(A) that it was appropriate and necessary to regulate 
coal- and oil-fired EGUs under CAA section 112 and added such units to 
the list of source categories subject to regulation under CAA section 
112(d). In making that finding, the EPA considered the Utility Study, 
the Mercury Study, the NAS Study, and certain additional information, 
including information about Hg emissions from coal-fired EGUs that the 
EPA obtained pursuant to an information collection request (ICR) under 
the authority of CAA section 114. 65 FR 79826-27.

B. What is the litigation history of this final rule?

    Shortly after issuance of the December 2000 finding, an industry 
group challenged that finding in the Court of Appeals for the D.C. 
Circuit (D.C. Circuit). Utility Air Regulatory Group (UARG) v. EPA, 
2001 WL 936363, No. 01-1074 (D.C. Cir. July 26, 2001). The D.C. Circuit 
dismissed the lawsuit holding that it did not have jurisdiction because 
CAA section 112(e)(4) provides, in pertinent part, that ``no action of 
the Administrator * * * listing a source category or subcategory under 
subsection (c) of this section shall be a final agency action subject 
to judicial review, except that any such action may be reviewed under 
section 7607 of (the CAA) when the Administrator issues emission 
standards for such pollutant or category.'' Id. (emphasis added).
    Pursuant to a settlement agreement, the deadline for issuing 
emission standards was March 15, 2005. However, instead of issuing 
emission standards pursuant to CAA section 112(d), on March 29, 2005, 
the EPA issued the Section 112(n) Revision Rule (2005 Action). That 
action delisted EGUs after finding that it was neither appropriate nor 
necessary to regulate such units under CAA section 112. In addition, on 
May 18, 2005, the EPA issued the Clean Air Mercury Rule (CAMR). 70 FR 
28606. That rule established standards of performance for emissions of 
Hg from new and existing coal-fired EGUs pursuant to CAA section 111.
    Environmental groups, states, and tribes challenged the 2005 Action 
and CAMR. Among other things, the environmental and state petitioners 
argued that the EPA could not remove EGUs from the CAA section 112(c) 
source category list without following the requirements of CAA section 
112(c)(9).
    On February 8, 2008, the D.C. Circuit vacated both the 2005 Action 
and CAMR. The D.C. Circuit held that the EPA failed to comply with the 
requirements of CAA section 112(c)(9) for delisting source categories. 
Specifically, the D.C. Circuit held that CAA section 112(c)(9) applies 
to the removal of ``any source category'' from the CAA section 112(c) 
list, including EGUs. The D.C. Circuit found that, by enacting CAA 
section 112(c)(9), Congress limited the EPA's discretion to reverse 
itself and remove source categories from the CAA section 112(c) list. 
The D.C. Circuit found that the EPA's contrary position would ``nullify 
Sec.  112(c)(9) altogether.'' New Jersey v. EPA, 517 F.3d 574, 583 
(D.C. Cir. 2008). The D.C. Circuit did not reach the merits of 
petitioners' arguments on CAMR, but vacated CAMR for existing sources 
because coal-fired EGUs were already listed sources under CAA section 
112. The D.C. Circuit reasoned that even under the EPA's own 
interpretation of the CAA, regulation of existing sources' Hg emissions 
under CAA section 111 was prohibited if those sources were a listed 
source category under CAA section 112.\6\ Id. The D.C. Circuit vacated 
and remanded CAMR for new sources because it concluded that the 
assumptions the EPA made when issuing CAMR for new sources were no 
longer accurate (i.e., that there would be no CAA section 112 
regulation of EGUs and that the CAA section 111 standards would be 
accompanied by standards for existing sources). Id. at 583-84. Thus, 
CAMR and the 2005 Action became null and void.
---------------------------------------------------------------------------

    \6\ In CAMR and the 2005 Action, EPA interpreted section 111(d) 
of the Act as prohibiting the Agency from establishing an existing 
source standard of performance under CAA section 111(d) for any HAP 
emitted from a particular source category, if the source category is 
regulated under CAA section 112.
---------------------------------------------------------------------------

    On December 18, 2008, several environmental and public health 
organizations filed a complaint in the U.S. District Court for the 
District of Columbia.\7\ They alleged that the Agency had failed to 
perform a nondiscretionary duty under CAA section 304(a)(2), by failing 
to promulgate final CAA section 112(d) standards for HAP from coal- and 
oil-fired EGUs by the statutorily-mandated deadline, December 20, 2002, 
2 years after such sources were listed under CAA section 112(c). The 
EPA settled that litigation. The consent decree resolving the case 
requires the EPA to sign a notice of proposed rulemaking setting forth 
the EPA's proposed CAA section 112(d) emission standards for coal- and 
oil-fired EGUs by March 16, 2011, and a notice of final rulemaking by 
December 16, 2011.\8\
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    \7\ American Nurses Association, Chesapeake Bay Foundation, 
Inc., Conservation Law Foundation, Environment America, 
Environmental Defense Fund, Izaak Walton League of America, Natural 
Resources Council of Maine, Natural Resources Defense Council, 
Physicians for Social Responsibility, Sierra Club, The Ohio 
Environmental Council, and Waterkeeper Alliance, Inc. (Civ. No. 
1:08-cv-02198 (RMC)).
    \8\ The consent decree originally required EPA to sign a notice 
of final rulemaking no later than November 16, 2011; however, on 
October 21, 2011, pursuant to paragraph 6 of the consent decree, the 
parties agreed to a 30-day extension of the final rule deadline. As 
stated in the stipulation memorializing the extension, the parties 
agreed to the extension of 30 days because EPA provided an 
additional 30 days for public comment and the time was necessary to 
respond to comments submitted on the proposed rule.
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C. What is the relationship between this final rule and other 
combustion rules?

1. CAA Section 111
    The EPA promulgated revised NSPS for SO2, nitrogen 
oxides (NOX), and PM under CAA section 111 for EGUs (40 CFR 
part 60, subpart Da) and industrial boilers (IB) (40 CFR part 60, 
subparts Db and Dc) on February 27, 2006 (71 FR 9866). As noted 
elsewhere, in this action we are finalizing certain amendments to 40 
CFR part 60, subpart Da. In developing this final rule, we considered 
the monitoring, testing, and recordkeeping requirements of the existing 
and revised NSPS to avoid duplicating requirements to the extent 
possible.
2. CAA Section 112
    The EPA has previously developed other non-EGU combustion-related 
NESHAP under CAA section 112(d). The EPA promulgated final NESHAP for 
major source industrial, commercial and institutional boilers and 
process heaters (IB) and area source industrial, commercial and 
institutional boilers on March 21, 2011 (40 CFR part 63, subpart DDDDD, 
76 FR 15608; and subpart JJJJJJ, 76 FR 15249, respectively), and 
promulgated standards for stationary combustion turbines (CT) on March 
5, 2004 (40 CFR part 63 subpart YYYY; 69 FR 10512). In addition to 
these three NESHAP, on March 21, 2011, the EPA also promulgated final 
CAA section 129 standards for commercial and institutional solid waste 
incineration (CISWI) units, including energy recovery units (40 CFR 
part 60, subparts CCCC (NSPS) and DDDD (emission guidelines); 76 FR 
15704); and a definition of non-hazardous secondary materials that are 
solid waste (Non-hazardous Solid Waste Definition Rule (40 CFR part 
241, subpart B; 76 FR 15456)). Electric generating units and IB

[[Page 9309]]

that combust fossil fuel and solid waste, as that term is defined by 
the Administrator pursuant to the Resource Conservation and Recovery 
Act (RCRA), see 76 FR 15456, will be subject to standards issued 
pursuant to CAA section 129 (e.g., CISWI), unless they meet one of the 
exemptions in CAA section 129(g)(1). Clean Air Act section 129 
standards are discussed in more detail below.
    The two IB (Boiler) NESHAP, the CT NESHAP, and this final rule will 
regulate HAP emissions from sources that combust fossil fuels for 
electrical power, process operations, or heating. The differences among 
these rules are due to the size of the units (megawatt (MW), megawatt-
electric (MWe), or British thermal unit per hour (Btu/hr)), the boiler/
furnace technology, and/or the portion of their electrical output (if 
any) for sale to any utility power distribution systems.
    Pursuant to the CAA, an EGU is ``any fossil fuel fired combustion 
unit of more than 25 megawatts that serves a generator that produces 
electricity for sale. A unit that cogenerates steam and electricity and 
supplies more than one-third of its potential electric output capacity 
and more than 25 megawatts electrical output to any utility power 
distribution system for sale shall be considered an electric utility 
steam generating unit.'' CAA section 112(a)(8). We consider all of the 
MW ratings quoted in the final rule to be the original rated nameplate 
capacity of the unit. We consider cogeneration to be the simultaneous 
production of power (electricity) and another form of useful thermal 
energy (usually steam or hot water) from a single fuel-consuming 
process.
    We consider any combustion unit, regardless of size, that produces 
steam to serve a generator that produces electricity exclusively for 
industrial, commercial, or institutional purposes (i.e., makes no sales 
to the national electrical distribution grid) to be an IB unit. We do 
not consider a fossil fuel-fired combustion unit that serves a 
generator that produces electricity for sale to be an EGU under the 
final rule if the size of the combustion unit is less than or equal to 
25 MW. Units that are 25 MW or less are likely subject to one of the 
two Boiler NESHAP.
    Because of the combustion technology of simple-cycle and combined-
cycle stationary CTs (with the exception of integrated gasification 
combined cycle (IGCC) units that burn gasified coal or petroleum coke 
synthesis gas/syngas), we do not consider these CTs to be EGUs for 
purposes of this final rule.\9\
---------------------------------------------------------------------------

    \9\ The CT NESHAP regulates HAP emissions from all simple-cycle 
and combined-cycle stationary CTs producing electricity or steam for 
any purpose.
---------------------------------------------------------------------------

    The December 2000 listing discussed above did not list natural gas-
fired EGUs. Thus, this final rule does not regulate a unit that 
otherwise meets the CAA section 112(a)(8) definition of an EGU but that 
combusts natural gas exclusively or natural gas in combination with 
another fossil fuel where the natural gas constitutes 90.0 percent or 
more of the average annual heat input during any 3 consecutive calendar 
years or 85.0 percent or more of the annual heat input in one calendar 
year. We consider such units to be natural gas-fired EGUs 
notwithstanding the combustion of some coal or oil (or derivative 
thereof) and such units are not subject to this final rule.
    The CAA does not define the terms ``fossil fuel-fired'' and 
``fossil fuel.'' In this rule, we are finalizing definitions for both 
terms for purposes of this rule. The definition of ``fossil fuel-
fired'' will help determine the applicability of the final rule to 
combustion units that sell electricity to the utility power 
distribution system. The definition of ``fossil fuel-fired'' 
establishes the amount of fossil fuel combustion necessary to make a 
unit ``fossil fuel-fired'' and hence potentially subject to this final 
rule. These definitions will help determine applicability of the final 
rule to units that primarily fire non-fossil fuels (e.g., biomass) but 
generally start up using either natural gas or distillate oil and may 
use these fuels (or coal) during normal operation for flame 
stabilization.
    In addition, the EPA is finalizing in the definition of ``fossil 
fuel-fired'' that, among other things, an EGU must fire coal or oil for 
more than 10.0 percent of the average annual heat input during any 3 
consecutive calendar years or for more than 15.0 percent of the annual 
heat input during any one calendar year after the applicable compliance 
date in order to be considered a fossil fuel-fired EGU subject to this 
final rule. The EPA has based these threshold percentage values on the 
definition of ``oil-fired'' in the Acid Rain Program (ARP) found at 40 
CFR 72.2. Though the EPA does not have annual heat input data for, for 
example, biomass co-fired EGUs because their use is not yet 
commonplace, we believe this definition accounts for the use of fossil 
fuels for flame stabilization use without inappropriately subjecting 
such units to this final rule.
    Units that do not meet the EGU definition will in most cases be 
considered IB units subject to one of the two Boiler NESHAP. Thus, for 
example, a biomass-fired EGU, regardless of size, that utilizes fossil 
fuels for startup and flame stabilization purposes only (i.e., less 
than or equal to 10.0 percent of the average annual heat input in any 3 
consecutive calendar years or less than or equal to 15.0 percent of the 
annual heat input during any one calendar year) is not considered to be 
a fossil fuel-fired EGU under this final rule.
    A cogeneration facility that sells electricity to any utility power 
distribution system equal to more than one-third of its potential 
electric output capacity and more than 25 MW will be considered an EGU 
if the facility is fossil fuel-fired as that term is defined in the 
final rule.
    We recognize that different CAA section 112 rules may impact a 
particular unit at different times. For example, the Boiler NESHAP may 
cover some cogeneration units. Such a unit may decide to increase or 
decrease the proportion of production output it supplies to the 
electric utility grid, thus causing the unit to meet the EGU 
cogeneration criteria (i.e., greater than one-third of its potential 
output capacity and greater than 25 MW). A unit subject to one of the 
Boiler NESHAP that increases its electricity output and meets the 
definition of an EGU would be subject to the final EGU NESHAP.
    Another rule intersection may occur where one or more coal- or oil-
fired EGU(s) share an air pollution control device (APCD) and/or an 
exhaust stack with one or more similarly-fueled IB unit(s). To 
demonstrate compliance with two different rules, either the emissions 
would need to be apportioned to the appropriate source or the more 
stringent emission limit would need to be met. Data needed to apportion 
emissions are not currently required by this final rule or the final 
boiler NESHAP and are not otherwise available. Therefore, the EPA is 
finalizing the requirement to comply with the more stringent emission 
limit.
3. CAA Section 129
    Clean Air Act section 129 regulates units that combust ``non-
hazardous secondary materials,'' as that term is defined by the 
Administrator under the Resource Conservation and Recovery Act (RCRA), 
that are ``solid wastes.'' On March 21, 2011, the EPA promulgated the 
final Non-Hazardous Solid Waste Definition Rule (76 FR 15456). Any EGU 
that combusts any solid waste as defined in that final rule is a solid 
waste

[[Page 9310]]

incineration unit subject to emissions standards under CAA section 129.
    In the Non-Hazardous Solid Waste Definition Rule, the EPA 
determined that coal refuse from current mining operations is not 
considered to be a ``solid waste'' if it is not discarded. Coal refuse 
that is in legacy coal refuse piles is considered a ``solid waste'' 
because it has been discarded. However, if discarded coal refuse is 
processed in the same manner as currently mined coal refuse, the coal 
refuse would not be considered a solid waste but instead would be 
considered a product fossil fuel. Therefore, the combustion of such 
material by a combustion unit would not subject that unit to regulation 
under CAA section 129. Instead, the unit would be subject to this final 
rule if it meets the definition of EGU. In the proposed rule, we 
assumed that all units that combust coal refuse and otherwise meet the 
definition of a coal-fired EGU are in fact combusting newly mined coal 
refuse or coal refuse from legacy piles that has been processed such 
that it is not a solid waste. We did not receive any information since 
proposal that would cause us to revise this determination in the final 
rule.
    Further, CAA section 129(g)(1)(B) exempts from regulation

    ``* * * qualifying small power production facilities, as defined 
in section 796(17)(C) of Title 16, or qualifying cogeneration 
facilities, as defined in section 796(18)(B) of Title 16, which burn 
homogeneous waste * * * for the production of electric energy or in 
the case of qualifying cogeneration facilities which burn 
homogeneous waste for the production of electric energy and steam or 
forms of useful energy (such as heat) which are used for industrial, 
commercial, heating or cooling purposes * * *''

If the ``homogeneous waste'' material that such facilities combust is 
also a fossil fuel, and those facilities otherwise meet the definition 
of an EGU under CAA section 112(a)(8), then those facilities are exempt 
from regulation under CAA section 129 but covered under this final 
rule. For example, a qualifying small power production facility or 
cogeneration facility combusting only coal refuse that is a solid waste 
and a ``homogenous waste,'' as that term is defined in the final CAA 
section 129 CISWI standards, would be subject to this final rule if the 
unit also met the definition of EGU.

D. What are the health effects of pollutants emitted from coal- and 
oil-fired EGUs?

    This final rule protects air quality and promotes public health by 
reducing emissions of some of the HAP listed in CAA section 112(b)(1). 
Utilities are by far the largest anthropogenic source of Hg in the U.S. 
In addition, EGUs are the largest source of HCl, hydrogen fluoride 
(HF), and selenium (Se) emissions, and a major source of metallic HAP 
emissions including As, chromium (Cr), Ni, and others. The discrepancy 
is even greater now that almost all other major source categories have 
been required to control Hg and other HAP under CAA section 112. In 
2005, U.S. EGUs emitted 50 percent of total domestic anthropogenic Hg 
emissions, 62 percent of total As emissions, 39 percent of total 
cadmium (Cd) emissions, 22 percent of total Cr emissions, 82 percent of 
total HCl emissions, 62 percent of total HF emissions, 28 percent of 
total Ni emissions, and 83 percent of total Se emissions.\10\ Exposure 
to these HAP, depending on exposure duration and levels of exposures, 
is associated with a variety of adverse health effects. These adverse 
health effects may include chronic health disorders (e.g., irritation 
of the lung, skin, and mucus membranes; detrimental effects on the 
central nervous system; damage to the kidneys; and alimentary effects 
such as nausea and vomiting). Two of the HAP are classified as human 
carcinogens (As and CrVI) and two as probable human carcinogens (Cd and 
Ni). See 76 FR 25003-25005 for a fuller discussion of the health 
effects associated with these pollutants.
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    \10\ From 2005 National-Scale Air Toxics Assessment (NATA), 
available at http://www.epa.gov/ttn/atw/nata2005/.
---------------------------------------------------------------------------

III. Appropriate and Necessary Finding

A. Overview

    In December 2000, the EPA issued a finding pursuant to CAA section 
112(n)(1)(A) that it was appropriate and necessary to regulate coal- 
and oil-fired EGUs under CAA section 112 and added such units to the 
list of source categories subject to regulation under section 112(d). 
The EPA found that it was appropriate to regulate HAP emissions from 
coal- and oil-fired EGUs because, among other reasons, Hg is a hazard 
to public health, and U.S. EGUs are the largest domestic source of Hg 
emissions. The EPA also found it appropriate to regulate HAP emissions 
from EGUs because it had identified certain control options that would 
effectively reduce HAP emissions from U.S. EGUs. The EPA found that it 
was necessary to regulate HAP emissions from U.S. EGUs under section 
112 because the implementation of other requirements under the CAA will 
not adequately address the serious public health and environmental 
hazards arising from HAP emissions from U.S. EGUs and that CAA section 
112 is intended to address HAP emissions. See 76 FR 24984-20985 (for 
further discussion of 2000 finding).
    Because several years had passed since the 2000 finding, the EPA 
performed additional technical analyses for the proposed rule, even 
though those analyses were not required. These analyses included a 
national-scale Hg risk assessment focused on populations with high 
levels of self-caught fish consumption, and a set of 16 case studies of 
inhalation cancer risks for non-Hg HAP. The analyses confirm that it 
remains appropriate and necessary to regulate U.S. EGUs under section 
112.
    In the preamble to the proposed rule, the EPA reported the results 
of those additional technical analyses. Those analyses confirmed the 
2000 finding that it is appropriate to regulate U.S. EGUs under section 
112 by demonstrating that (1) Hg continues to pose a hazard to public 
health because up to 28 percent of watersheds were estimated to have Hg 
deposition attributable to U.S. EGUs that contributes to potential 
exposures above the reference dose for methylmercury (MeHg RfD), a 
level above which there is increased risk of neurological effects in 
children, (2) non-Hg HAP emissions pose a hazard to public health 
because case studies at 16 facilities demonstrated that lifetime cancer 
risks at 4 of the facilities exceed 1 in 1 million, and (3) U.S. EGUs 
remain the largest domestic source of Hg emissions and several HAP 
(e.g., HF, Se, HCl), and are among the largest contributors for other 
HAP (e.g., As, Cr, Ni, HCN). Thus, in the preamble to the proposed 
rule, the EPA found that Hg and non-Hg HAP emissions from U.S. EGUs 
pose hazards to public health, which confirmed the 2000 finding and 
demonstrated that it remains appropriate to regulate U.S. EGUs under 
section 112.
    In the preamble to the proposed rule, the EPA also found that it is 
appropriate to regulate U.S. EGUs because (1) Hg emissions pose a 
hazard to the environment and wildlife, adversely impacting species of 
fish-eating birds and mammals, (2) acid gas HAP pose a hazard to the 
environment because they contribute to aquatic acidification, and (3) 
effective controls are available to reduce Hg and non-Hg HAP emissions 
from U.S. EGUs.
    The additional analyses reported in the preamble to the proposed 
rule also confirmed that it remains necessary to regulate U.S. EGU 
under CAA section 112. These analyses demonstrated that (1) Hg 
emissions from U.S. EGUs remaining in 2016 are reasonably anticipated 
to pose a hazard to public health after imposition of other CAA

[[Page 9311]]

requirements, such as the Cross-State Air Pollution Rule (CSAPR); (2) 
U.S. EGUs are reasonably anticipated to remain the largest source of Hg 
in the U.S. and thus contribute to the risk associated with exposure to 
MeHg; (3) Hg emissions from U.S. EGUs after imposition of the 
requirements of the CAA were projected to be 29 tons per year in 2016, 
similar to levels of Hg emitted today, indicating that further 
substantial reductions in Hg emissions are not reasonably anticipated 
without federal regulations on Hg from U.S. EGUs; (4) we cannot be 
certain that the identified cancer risks attributable to non-Hg 
emissions from U.S. EGUs will be addressed through imposition of the 
requirements of the CAA because companies can use compliance strategies 
for criteria pollutants that do not achieve HAP co-benefits (e.g., 
purchasing allowances in a trading program); and (5) we cannot ensure 
that Hg and non-Hg HAP emissions reductions achieved since 2005 would 
be permanent without federally binding regulations for Hg from U.S. 
EGUs.
    Since issuance of the proposed rule, the EPA has conducted peer 
reviews of the national-scale Hg risk assessment (Hg Risk TSD) and the 
approach for estimating chromium and nickel inhalation cancer risk in 
the case studies.11 12 The peer review of the Hg Risk TSD 
was conducted by EPA's independent Science Advisory Board (SAB). The 
SAB stated that it ``supports the overall design of and approach to the 
risk assessment and finds that it should provide an objective, 
reasonable, and credible determination of the potential for a public 
health hazard from mercury emitted from U.S. EGUs.'' \13\ SAB 
recommended several improvements to the data, methods and documentation 
of the analyses, which EPA has fully addressed in the revised Hg Risk 
TSD.
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    \11\ U.S. EPA. 2011a. National-Scale Assessment of Mercury Risk 
to Populations with High Consumption of Self-caught Freshwater Fish 
In Support of the Appropriate and Necessary Finding for Coal- and 
Oil-Fired Electric Generating Units. Office of Air Quality Planning 
and Standards. November. EPA-452/R-11-009.
    \12\ U.S. EPA. 2011b. Supplement to Non-mercury Case Study 
Chronic Inhalation Risk Assessment for the Utility MACT Appropriate 
and Necessary Analysis. Office of Air Quality Planning and 
Standards. November.
    \13\ U.S. Environmental Protection Agency-Science Advisory Board 
(U.S. EPA-SAB). 2011. Peer Review of EPA's Draft National-Scale 
Mercury Risk Assessment. EPA-SAB-11-017. September. Available on the 
Internet at http://yosemite.epa.gov/sab/sabproduct.nsf/
BCA23C5B7917F5BF8525791A0072CCA1/$File/EPA-SAB-11-017-unsigned.pdf.
---------------------------------------------------------------------------

    As described in the revised Hg Risk TSD, after addressing comments 
from the peer review, the revised results show that up to 29 percent of 
modeled watersheds are estimated to have Hg deposition attributable to 
U.S. EGUs that contributes to potential exposures above the MeHg RfD, 
an increase of one percentage point from the results reported in the 
proposed rule. We conclude that Hg emissions from EGUs pose a hazard to 
public health based on the total of 29 percent of modeled watersheds at 
risk. Our analyses show that of the 29 percent of watersheds with 
population at-risk, in 10 percent of those watersheds U.S. EGU 
deposition alone without considering deposition from other sources 
would lead to potential exposures that exceed the MeHg RfD, and in 24 
percent of those watersheds, total potential exposures to MeHg exceed 
the RfD and U.S. EGUs contribute at least 5 percent to Hg 
deposition.14 15 Each of these results independently 
supports our conclusion that Hg emissions from EGUs pose hazards to 
public health.
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    \14\ Because some watersheds with exposures sufficient to exceed 
the RfD with Hg deposition from U.S. EGUs alone without considering 
deposition from other sources also have U.S. EGU contributions of 
more than 5 percent of total Hg deposition, there is some overlap 
between the two risk metrics. This explains why the total percent of 
watersheds exceeding either risk metric is less than the sum of the 
individual risk metrics.
    \15\ Requiring at least a 5 percent EGU contribution is a 
conservative approach given the increasing risks associated with 
incremental exposures above the RfD. Because we are finding 24 
percent of watersheds with populations potentially at risk even 
using this conservative approach, we have confidence that emissions 
of Hg from U.S. EGUs are causing a hazard to public health.
---------------------------------------------------------------------------

    The peer review of the approach to estimate Ni and Cr cancer risk 
in the case studies also supported EPA's assessment. The EPA enhanced 
this analysis in response to the peer review and public comments. The 
results of those revised analyses show that 6 of 16 modeled facilities 
have lifetime cancer risks greater than 1 in a million, thus confirming 
that non-Hg HAP emissions from U.S. EGUs remain a hazard to public 
health. Given Congress' determination that categories of sources that 
emit HAP resulting in a lifetime cancer risk greater than 1 in a 
million should not be removed from the CAA section 112(c) source 
category list and should continue to be regulated under CAA section 
112, the EPA concludes that risk above that level represents a hazard 
to public health.
    Based on our consideration of the peer reviews, public comments, 
and our updated analyses, we confirm the findings that Hg and non-Hg 
HAP emissions from U.S. EGUs pose hazards to public health and that it 
remains appropriate to regulate U.S. EGUs under CAA section 112. We 
also conclude that it remains appropriate to regulate U.S. EGUs under 
CAA section 112 because of the magnitude of Hg and non-Hg emissions, 
environmental effects of Hg and certain non-Hg emissions, and the 
availability of controls to reduce HAP emissions from EGUs.
    In addition, we conclude that the hazards to public health from Hg 
and non-Hg emissions from U.S. EGUs are reasonably anticipated to 
remain after imposition of the requirements of the CAA. The same is 
true for hazards to the environment. Thus, we confirm that it is 
necessary to regulate U.S. EGUs under CAA section 112.

B. Peer Review of the Hg Risk TSD Supporting the Appropriate and 
Necessary Finding for Coal and Oil-Fired EGUs and EPA Response

    In the preamble to the proposed rule, the EPA stated that ``in 
making the finding that it remains appropriate and necessary to 
regulate EGUs to address public health and environmental hazards 
associated with emissions of Hg and Non-Hg HAP from EGUs, the EPA 
determined that the Hg Risk TSD supporting EPA's 2011 review of U.S. 
EGU health impacts should be peer-reviewed.'' \16\ We also indicated 
that due to the court-ordered schedule for the final rule, we planned 
to conduct the peer review as expeditiously as possible after issuance 
of the proposed rule, and that the results of the peer review and any 
EPA response would be published before the final rule. Due to the 
extension of the public comment period and the volume of public 
comments received on the analyses supporting the proposed rule, we were 
unable to publish EPA's response prior to signature of the final rule.
---------------------------------------------------------------------------

    \16\ 76 FR 25012.
---------------------------------------------------------------------------

    The EPA's response to the peer review the Hg Risk TSD is fully 
documented in the revised Technical Support Document (TSD): National-
Scale Assessment of Hg Risk to Populations of High Consumption of Self-
Caught Fish In Support of the Appropriate and Necessary Finding for 
Coal and Oil-Fired Electric Generating Units.\17\ The following 
sections describe the peer review process that we followed, provide the 
peer review charge questions presented to the peer review panel, 
summarize the key recommendations from the peer review, and summarize 
our responses to those recommendations.
---------------------------------------------------------------------------

    \17\ U.S. EPA, 2011a.

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[[Page 9312]]

1. Summary of Peer Review Process
    Peer review is consistent with EPA's open and transparent process 
to ensure that the Agency's scientific assessments and rulemakings are 
based on the best science available. This regulatory action was 
supported by the Hg Risk TSD, which is a highly influential scientific 
assessment. Therefore, the EPA conducted a peer review in accordance 
with OMB's Final Information Quality Bulletin for Peer Review \18\ as 
described below. All the materials related to the peer review, 
including the SAB's final report, can be found in the docket for this 
rulemaking.
---------------------------------------------------------------------------

    \18\ Office of Management and Budget (OMB). 2004. Final 
Information Quality Bulletin for Peer Review. December. Available on 
the Internet at http://www.whitehouse.gov/omb/memoranda_fy2005_m05-03.
---------------------------------------------------------------------------

    The EPA commissioned the peer review through EPA's SAB, which 
provides independent advice and peer review to EPA's Administrator on 
the scientific and technical aspects of environmental issues. The SAB 
convened a 22-member peer review committee. The SAB process for 
selecting the panel began with two Federal Register Notices requesting 
nominations for the Mercury Review Panel.\19\ Based on nominations 
received, a list of potential panel members, along with bio-sketches, 
was posted for public comment on the SAB Web site on April 15, 2011. 
The members of the Mercury Review Panel were announced on May 24, 2011. 
The membership of the panel included representatives of 16 academic 
institutions, 4 state health or environmental agencies, 1 federal 
agency, and 1 utility industry organization.\20\ The panel held a 
public meeting in Research Triangle Park, NC, on June 15-17, 2011, 
which included the opportunity for public comment on the Hg Risk TSD 
and the peer review process.\21\ At the June 15-17 public meeting, the 
panel completed a draft peer review report. The minutes of that meeting 
and the draft peer review report were posted to the SAB public Web site 
within the public comment period for the proposed rule. The panel 
discussed the draft report at a public teleconference on July 12, 2011, 
during which additional opportunities for public comment were 
provided,\22\ and submitted a revised draft for quality review by the 
Chartered SAB before the end of the public comment period on the rule. 
The Chartered SAB held a public teleconference on September 7, 2011, to 
conduct a quality review of the draft report; this teleconference also 
included a final opportunity for public comment.\23\ The SAB submitted 
its final report to EPA on September 29, 2011.\24\ Notice of all the 
meetings was published in the Federal Register and all of the materials 
discussed at the SAB meetings, including technical documents, 
presentations, meeting minutes, and draft reports were posted for 
public access on the SAB Web site \25\ and were added to the docket for 
the final rule on October 14, 2011.
---------------------------------------------------------------------------

    \19\ 76 FR 10896 and 76 FR 17649. The first notice requested 
nominations to a Clean Air Scientific Advisory Committee (CASAC) 
panel. Upon review of the scope of the CASAC charter (resulting from 
a public comment received in response to the first notice), the SAB 
determined that it would be more appropriate to form a panel under 
the SAB, rather than CASAC. The second notice announced this change 
and requested nominations for the SAB panel.
    \20\ The full list of panel members is documented at http://
yosemite.epa.gov/sab/sabproduct.nsf/0/
9F048172004D93BB8525783900503486/$File/
Determination%20memo%20with%20addendum-05.24.11.pdf.
    \21\ 76 FR 29746.
    \22\ 76 FR 39102.
    \23\ 76 FR 50729.
    \24\ U.S. EPA-SAB, 2011. Peer Review of EPA's Draft National-
Scale Mercury Risk Assessment.
    \25\ See http://yosemite.epa.gov/sab/sabpeople.nsf/WebCommittees/BOARD.
---------------------------------------------------------------------------

2. Peer Review Charge Questions
    The EPA asked the SAB to comment on the Hg Risk TSD, including the 
overall design and approach and the use of specific models and key 
assumptions. The EPA also asked the SAB to comment on the extent to 
which specific facets of the assessment were well characterized in the 
Hg Risk TSD. The specific charge questions are listed below:
    Question 1. Please comment on the scientific credibility of the 
overall design of the mercury risk assessment as an approach to 
characterize human health exposure and risk associated with U.S. EGU 
mercury emissions (with a focus on those more highly exposed).
    Question 2. Are there any additional critical health endpoint(s) 
besides IQ loss, which could be quantitatively estimated with a 
reasonable degree of confidence to supplement the mercury risk 
assessment (see section 1.2 of the Mercury Risk TSD for an overview of 
the risk metrics used in the risk assessment)?
    Question 3. Please comment on the benchmark used for identifying a 
potentially significant public health impact in the context of 
interpreting the IQ loss risk metric (i.e., an IQ loss of 1 to 2 points 
or more representing a potential public health hazard). Is there any 
scientifically credible alternate decrement in IQ that should be 
considered as a benchmark to guide interpretation of the IQ risk 
estimates (see section 1.2 of the Mercury Risk TSD for additional 
detail on the benchmark used for interpreting the IQ loss estimates)?
    Question 4: Please comment on the spatial scale used in defining 
watersheds that formed the basis for risk estimates generated for the 
analysis (i.e., use of 12-digit hydrologic unit code classification). 
To what extent do [Hydrologic Unit Code] HUC12 watersheds capture the 
appropriate level of spatial resolution in the relationship between 
changes in mercury deposition and changes in MeHg fish tissue levels? 
(see section 1.3 and Appendix A of the Mercury Risk TSD for additional 
detail on specifying the spatial scale of watersheds used in the 
analysis).
    Question 5: Please comment on the extent to which the fish tissue 
data used as the basis for the risk assessment are appropriate and 
sufficient given the goals of the analysis. Please comment on the 
extent to which focusing on data from the period after 1999 increases 
confidence that the fish tissue data used are more likely to reflect 
more contemporaneous patterns of Hg deposition and less likely to 
reflect earlier patterns of Hg deposition. Are there any additional 
sources of fish tissue MeHg data that would be appropriate for 
inclusion in the risk assessment?
    Question 6: Given the stated goal of estimating potential risks to 
highly exposed populations, please comment on the use of the 75th 
percentile fish tissue MeHg value (reflecting targeting of larger but 
not the largest fish for subsistence consumption) as the basis for 
estimating risk at each watershed. Are there scientifically credible 
alternatives to use of the 75th percentile in representing potential 
population exposures at the watershed level?
    Question 7: Please comment on the extent to which characterization 
of consumption rates and the potential location for fishing activity 
for high-end self-caught fish consuming populations modeled in the 
analysis are supported by the available study data cited in the Mercury 
Risk TSD. In addition, please comment on the extent to which 
consumption rates documented in Section 1.3 and in Appendix C of the 
Mercury Risk TSD provide appropriate representation of high-end fish 
consumption by the subsistence population scenarios used in modeling 
exposures and risk. Are there additional data on consumption behavior 
in subsistence populations active at inland freshwater water bodies 
within the continental U.S.?
    Question 8: Please comment on the approach used in the risk 
assessment of

[[Page 9313]]

assuming that a high-end fish consuming population could be active at a 
watershed if the ``source population'' for that fishing population is 
associated with that watershed (e.g., at least 25 individuals of that 
population are present in a U.S. Census tract intersecting that 
watershed). Please identify any additional alternative approaches for 
identifying the potential for population exposures in watersheds and 
the strengths and limitations associated with these alternative 
approaches (additional detail on how EPA assessed where specific high-
consuming fisher populations might be active is provided in section 1.3 
and Appendix C of the Mercury Risk TSD).
    Question 9: Please comment on the draft risk assessment's 
characterization of the limitations and uncertainty associated with 
application of the Mercury Maps approach (including the assumption of 
proportionality between changes in mercury deposition over watersheds 
and associated changes in fish tissue MeHg levels) in the risk 
assessment. Please comment on how the output of CMAQ [Community 
Multiscale Air Quality] modeling has been integrated into the analysis 
to estimate changes in fish tissue MeHg levels and in the exposures and 
risks associated with the EGU-related fish tissue MeHg fraction (e.g., 
matching of spatial and temporal resolution between CMAQ modeling and 
HUC12 watersheds). Given the national scale of the analysis, are there 
recommended alternatives to the Mercury Maps approach that could have 
been used to link modeled estimates of mercury deposition to monitored 
MeHg fish tissue levels for all the watersheds evaluated? (additional 
detail on the Mercury Maps approach and its application in the risk 
assessment is presented in section 1.3 and Appendix E of the Mercury 
Risk TSD).
    Question 10: Please comment on the EPA's approach of excluding 
watersheds with significant non-air loadings of mercury as a method to 
reduce uncertainty associated with application of the Mercury Maps 
approach. Are there additional criteria that should be considered in 
including or excluding watersheds?
    Question 11: Please comment on the specification of the 
concentration-response function used in modeling IQ loss. Please 
comment on whether EPA, as part of uncertainty characterization, should 
consider alternative concentration-response functions in addition to 
the model used in the risk assessment. Please comment on the extent to 
which available data and methods support a quantitative treatment of 
the potential masking effect of fish nutrients (e.g., omega-3 fatty 
acids and selenium) on the adverse neurological effects associated with 
mercury exposure, including IQ loss (detail on the concentration-
response function used in modeling IQ loss can be found in section 1.3 
of the Mercury Risk TSD).
    Question 12: Please comment on the degree to which key sources of 
uncertainty and variability associated with the risk assessment have 
been identified and the degree to which they are sufficiently 
characterized.
    Question 13: Please comment on the draft Mercury Risk TSD's 
discussion of analytical results for each component of the analysis. 
For each of the components below, please comment on the extent to which 
EPA's observations are supported by the analytical results presented 
and whether there is a sufficient characterization of uncertainty, 
variability, and data limitations, taking into account the models and 
data used: Mercury deposition from U.S. EGUs, fish tissue MeHg 
concentrations, patterns of Hg deposition with HG fish tissue data, 
percentile risk estimates, and number and frequency of watersheds with 
populations potentially at risk due to U.S. EGU mercury emissions.
    Question 14: Please comment on the degree to which the final 
summary of key observations in Section 2.8 is supported by the 
analytical results presented. In addition, please comment on the degree 
to which the level of confidence and precision in the overall analysis 
is sufficient to support use of the risk characterization framework 
described on page 18.
3. Summary of Peer Review Findings and Recommendations
    The SAB was generally supportive of EPA's approach.\26\ The SAB 
concluded, ``[i]n summary, based on its review of the draft Technical 
Support Document and additional information provided by EPA 
representatives during the public meetings, the SAB supports the 
overall design of and approach to the risk assessment and finds that it 
should provide an objective, reasonable, and credible determination of 
the potential for a public health hazard from mercury emitted from U.S. 
EGUs.'' \27\ The SAB further concluded, ``[t]he SAB regards the design 
of the risk assessment as suitable for its intended purpose, to inform 
decision-making regarding an `appropriate and necessary finding' for 
regulation of hazardous air pollutants from coal and oil-fired EGUs, 
provided that our recommendations are fully considered in the revision 
of the assessment.'' \28\
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    \26\ U.S. EPA-SAB, 2011.
    \27\ Id.
    \28\ Id.
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    The SAB report contained many recommendations for improving the Hg 
Risk TSD, which the SAB organized into three general themes: (1) 
Improve the clarity of the Hg Risk TSD regarding methods and 
presentation of results, (2) expand the discussion of sources of 
variability and uncertainty, and (3) de-emphasize IQ loss as an 
endpoint. In the following subsection, we provide EPA's response to 
these recommendations.
4. The EPA's Responses to Peer Review Recommendations
    In response to the peer review, the EPA has substantially revised 
the Hg Risk TSD. The revised Hg Risk TSD addresses all of the 
recommendations from the SAB and includes a detailed list of the 
specific revisions made to the Hg Risk TSD. Revisions in response to 
the main recommendations are summarized below. Italicized statements 
are the SAB's recommendations, which are followed by EPA's response.
     The watershed-focus of the Hg Risk TSD should be clearly 
stated early in the introduction to the document. We have stated 
clearly in the introduction to the revised Hg Risk TSD that the focus 
of the analysis is on scenarios of high fish consumption by subsistence 
level fishing populations, assessed at watersheds where there is the 
potential for such subsistence fishing activity. Specifically, we 
modeled risk for a set of subsistence fisher scenarios at those 
watersheds where (a) we have measured fish tissue Hg data and (b) it is 
reasonable to assume that subsistence-level fishing activity could 
occur. We emphasize the point that the analysis is not a representative 
population-weighted assessment of risk. Rather, it is based on 
evaluating these potential exposure scenarios.
     Because IQ does not fully capture the range of 
neurodevelopmental effects associated with Hg exposure, analysis of 
this endpoint should be deemphasized (and moved to an appendix) and 
primary focus should be placed on the MeHg RfD-based hazard quotient 
metric. We modified the structure of the revised Hg Risk TSD 
accordingly.
     Clarify the rationale for using a Hazard Quotient (HQ) at 
or above 1.5 as the basis for selecting potentially impacted 
watersheds. The SAB fully supported using HQ as the risk metric, but we 
revised the discussion in the Hg Risk TSD to clarify why we selected 
1.5

[[Page 9314]]

as the benchmark. We clarified that exposures above the RfD (i.e., an 
HQ above one) represent increasing risk of neurological health 
effects.\29\ We further clarified that the HQ is calculated to only one 
significant digit, based on the precision in the underlying RfD 
calculations. As a result, rounding convention requires that any values 
at or above 1.5 be expressed as an HQ of 2, while any values below 1.5 
(e.g., 1.49) be rounded to an HQ of 1. Thus, MeHg exposures leading to 
an HQ at or above 1.5 for pregnant women are considered above the RfD 
and are associated with increased risk of neurological health effects 
in children born to those mothers.
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    \29\ As stated in the preamble to the proposal, based on the 
current literature, exposures above the RfD contribute to risk of 
adverse effects.
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     Regarding the fish tissue dataset used in the Hg Risk TSD, 
clarify which species of Hg is reflected in the underlying samples and 
discuss the implications of differences across states in sampling 
protocols in introducing bias into the analysis. We clarified that in 
most cases, the fish tissue is measured for total Hg. Furthermore, 
based on the scientific literature,\30\ it is reasonable to assume that 
more than 90 percent of fish tissue Hg is MeHg. Therefore, we 
incorporated an Hg conversion factor \31\ into our exposure 
calculations to account for the fraction of total Hg that is MeHg in 
fish. We also expanded the discussion of uncertainty to address the 
potential for different sampling protocols across states to introduce 
bias into the Hg Risk TSD.
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    \30\ See the literature summary in Chapter 4 of U.S. EPA. 2000. 
Guidance for Assessing Chemical Contaminant Data for Use in Fish 
Advisories. Office of Science and Technology, Office of Water, 
Washington, DC EPA 823-B-00-007.
    \31\ In the Hg Risk TSD accompanying the proposed rule, we 
assumed that 100 percent of Hg in fish was MeHg. We derived the 0.95 
conversion factor for the revised Hg Risk TSD to reflect that most 
studies show that more than 90 percent of total Hg in fish is MeHg. 
See Chapter 4 of U.S. EPA, 2000.
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     Additional detail should be provided on the 
characteristics of the fish tissue Hg dataset, including its derivation 
and the distribution of specific attributes across the dataset (e.g., 
number of fish tissue samples and number of different waterbodies in a 
watershed, number of species reflected across watersheds). We included 
additional figures and tables describing the derivation of the 
watershed-level fish tissue Hg dataset, including the filtering steps 
applied to the original water body level data and the additional steps 
taken to generate the watershed-level fish tissue Hg percentile 
estimates. In addition, we included tables summarizing key attributes 
of the dataset (e.g., distribution of fish tissue sample size and 
number of species across the watershed-level estimates).
     Determine whether there is additional (more recent) fish 
tissue data for key states including Pennsylvania, New Jersey, Kentucky 
and Illinois where U.S. EGUs Hg deposition may be more significant. We 
expanded the fish tissue dataset by incorporating additional fish 
tissue data from the National Listing of Fish Advisories (NLFA), which 
included additional data for four states (MI, NJ, PA, and MN). We also 
obtained additional data for Wisconsin. These additional data expanded 
the number of watersheds in the analysis from 2,317 to 3,141, an 
increase of 36 percent. The additional watersheds improve coverage in 
areas with high levels of U.S. EGU-attributable Hg deposition, and thus 
increase our confidence in the overall results of the Hg Risk TSD.
     Include additional discussion of the potential that the 
low sampling rates reflected across many of the watersheds may low-bias 
the 75th percentile fish tissue Hg estimates used in estimating 
potential exposures. In addition, include a sensitivity analysis using 
the 50th percentile estimates to provide a bound on the risk. The SAB 
expressed support for the use of the 75th percentile fish tissue Hg 
value in the Hg Risk TSD, while recommending additional discussion of 
the issue. We provided additional description of the fish tissue 
dataset, including distribution of sample sizes and fish species across 
the watersheds, and an improved discussion of uncertainty and potential 
low bias resulting from estimation of the 75th percentile fish tissue 
levels. We also included a sensitivity analysis that used the 50th 
percentile watershed-level fish tissue Hg level. This sensitivity 
analysis showed that using the 50th percentile estimates resulted in a 
decrease in the number and percentage of modeled watersheds with 
populations potentially at-risk from U.S. EGU-attributable MeHg 
exposures, from 29 percent of watersheds exceeding either risk metric 
(i.e., MeHg exposure from U.S. EGUs alone exceeds the RfD or total MeHg 
exposure exceeds the RfD and U.S. EGUs contribute at least 5 percent) 
in the revised Hg Risk TSD to 26 percent in the sensitivity analysis in 
the revised Hg Risk TSD.
     Expand the discussion of caveats associated with the fish 
consumption rates used in the analysis. The SAB was generally 
supportive of the consumption rates used, while recommending additional 
discussion of caveats. We expanded the discussion of uncertainty 
related to the fish consumption rates to address the caveats identified 
by the SAB. The uncertainty discussion now explains (1) that high-end 
consumption rates for South Carolina reflect small sample sizes, and 
therefore may be more uncertain, (2) that the consumption surveys 
underlying the studies are older (i.e., mostly based on survey data 
from the 1990s) and behavior may have changed (i.e., consumption rates 
may have changed since the surveys were conducted), and (3) that 
consumption rates used in the Hg Risk TSD are annualized rather than 
seasonal rates and thus contribute little to overall uncertainty. None 
of these sources of uncertainty is associated with a particular 
directional bias (e.g., neither systematically higher nor lower risk).
     Verify whether the consumption rates are daily values 
expressed as annual averages and whether they are ``as caught'' or ``as 
prepared.'' We carefully reviewed the studies underlying the fish 
consumption rates used in the Hg Risk TSD and verified that the rates 
are annual averages of the daily consumption rates and that they 
represent as prepared estimates. We also expanded the explanation of 
the exposure calculations to describe more completely the exposure 
factors and equation used to generate the average daily MeHg intake 
estimates for the subsistence scenarios.
     Explain the criteria for exclusion of fish less than 7 
inches in length from analysis. We provided the rationale for the 7-
inch cutoff for edible fish used in the Hg Risk TSD. Seven inches 
represents a minimum size limit for a number of key edible freshwater 
fish species established at the state level. For example, Pennsylvania 
establishes 7 inches as the minimum size limit for both trout and 
salmon (other edible fish species such as bass, walleye and northern 
pike have higher minimum size limits). The impact of the 7-inch cutoff 
is likely to be quite small, as only 6 percent of potential fish 
samples were excluded due to this criterion.
     Identify the number of watersheds excluded from the 
analysis due to the criterion for excluding watersheds with less than 
25 members of a source population. The SAB was generally supportive of 
the approach used for identifying watersheds with the potential for 
subsistence activity, while recommending additional information on the 
results of applying the approach. We added a figure to illustrate the 
number of watersheds with fish tissue Hg data used to model risk for 
each of the subsistence fishing scenarios. For all scenarios except the 
female subsistence fishing scenario, the exposure scenarios 
significantly limited the number of

[[Page 9315]]

watersheds. Because the female subsistence fishing scenario does not 
differentiate with regard to ethnicity or socio-economic status (SES), 
we applied this scenario to all regions of the country and to all 
watersheds with fish tissue Hg data. This reflects our assumption that, 
given the generalized nature of the female subsistence fishing 
scenario, it is reasonable to assume that it could potentially occur at 
any watershed with fish tissue Hg data. The female subsistence fishing 
scenario included in the revised risk assessment is similar to the 
high-consuming female scenario included in the Hg Risk TSD.\32\ 
However, the female subsistence fishing scenario is applied to all 
watersheds, while in the scenario for the high-consuming low-income 
female angler, we only evaluated watersheds with a population of at 
least 25 low-income females. The female subsistence fishing scenario 
provides greater coverage geographically than the high-consuming low-
income female scenario. As described in the revised Hg Risk TSD, the 
EPA made this change in response to SAB's concerns regarding the 
potential exclusion of watersheds with fewer than 25 individuals and 
regarding coverage for high-end recreational fish consumption.\33\
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    \32\ In the Revised Hg Risk TSD, this population is also 
referred to as the ``typical female subsistence consumer.''
    \33\ This change led to a very small increase in the number of 
watersheds with populations potentially at-risk. In the Hg Risk TSD 
accompanying the proposed rule, approximately 4 percent of modeled 
watersheds were excluded based on the SES-based filtering criteria.
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     Enhance the discussion of the assumption of a linear 
relationship between changes in Hg deposition and changes in fish 
tissue Hg at the watershed level, including providing citations to more 
recent studies supporting the proportional relationship between changes 
in Hg deposition and changes in MeHg fish tissue levels. The SAB 
supported the assumption of a linear relationship between changes in Hg 
deposition and changes in fish tissue Hg at the watershed level, while 
recommending additional supporting language. We expanded our discussion 
of the scientific basis for the proportionality assumption and added 
citations for the more recent studies supporting the assumption. We 
also expanded the discussion of uncertainties associated with this 
assumption, including uncertainties related to the potential for 
sampled fish tissue Hg level to reflect previous Hg deposition, and the 
potential for non-air sources of Hg to contribute to sampled fish 
tissue Hg levels. Each of these sources of uncertainty may result in 
potential bias in the estimate of exposure associated with current 
deposition. If the fish tissue Hg levels are too high due to either 
previous Hg deposition or non-air sources of Hg, then the absolute 
level of exposure attributed to both total Hg deposition and U.S. EGU-
attributable Hg deposition will be biased high. However, the percent 
contribution from U.S. EGUs will not be affected as it depends entirely 
on deposition. The EPA took steps to minimize the potential for these 
biases by (1) only using fish tissue Hg samples from after 1999, and 
(2) screening out watersheds that either contained active gold mines or 
had other substantial non-U.S. EGU anthropogenic emissions of Hg. The 
SAB concluded that the EPA's approach to minimizing the potential for 
these biases to affect the results of the Hg Risk TSD is sound. In 
addition, we conducted several sensitivity analyses to gauge the impact 
of excluding watersheds with the potential for non-EGU Hg loading. We 
found that the estimates of the percent of modeled watersheds with 
populations potentially at-risk were largely insensitive to these 
exclusions, suggesting that any potential biases from including 
watersheds with potential non-air Hg loadings are likely to be small.
     Additional sources of variability should be discussed in 
terms of the degree to which they are reflected in the design of the 
risk assessment and the impact that they might have on risk estimates. 
These include: (1) The geographic patterns of populations of 
subsistence fishers, including how this factor interacts with the 
limited coverage we have for watersheds with our fish tissue Hg data, 
(2) the protocols used by states in collecting fish tissue Hg data, (3) 
body weights for subsistence fishing populations and the impact that 
this might have on exposure estimates, and (4) preparation and cooking 
methods which affect the conversion of fish tissue Hg levels (as 
measured) into ``as consumed'' values. We expanded the discussion of 
sources of variability in the revised Hg Risk TSD to more fully address 
these sources of variability. The Hg Risk TSD quantitatively reflected 
many aspects of variability, including spatial and temporal variability 
in Hg emissions, Hg deposition, fish tissue Hg levels, and subsistence 
behavior. After evaluating the aspects of variability assessed 
qualitatively in the Hg Risk TSD such as temporal response in fish 
tissue, we do not believe that quantitatively incorporating any of 
these aspects would substantially change the risk results given the 
stated goal of the analysis to identify watersheds where potential 
exposures to MeHg from self-caught fish consumption could exceed the 
RfD.
     Additional sources of uncertainty should be discussed in 
terms of their potential impact on risk estimates. These include: (1) 
Emissions inventory used in projecting total and U.S. EGU-attributable 
Hg deposition, including the projection of reductions in U.S. EGU 
emissions for the 2016 scenario, (2) air quality modeling with CMAQ 
including the prediction of future air quality scenarios, (3) ability 
of the Mercury Maps-based approach for relating Hg deposition to MeHg 
in fish to capture Hg hotspots, (4) the limited coverage that we have 
with fish tissue Hg data for watersheds in the U.S. and implications 
for the Hg Risk TSD, (5) the preparation factor used to estimate ``as 
consumed'' fish tissue Hg levels, (6) the proportionality assumption 
used to relate changes in Hg deposition to changes in fish tissue Hg 
levels at the watershed-level, (7) characterization of the spatial 
location of subsistence fisher populations (including the degree to 
which these provide coverage for high-consuming recreational fishers), 
and (8) application of the RfD to low SES populations and concerns that 
this could low-bias the risk estimates. We expanded the discussion of 
sources of uncertainty presented in the revised TSD to address more 
fully these sources of uncertainty and the potential impact on risk 
estimates. Regarding these eight additional sources of uncertainty, we 
have (1) evaluated the uncertainties in the emissions and determined 
that while an important source of uncertainty, we are not able to 
quantify emissions uncertainty in the risk analysis, but have 
determined that the emissions inventories and emissions models 
represent the best available methods for predicting Hg emissions in the 
U.S., (2) evaluated the uncertainties in the Hg deposition predictions 
and determined that while an important source of uncertainty, we are 
not able to quantify uncertainty in Hg deposition in the Hg Risk TSD. 
Moreover, the CMAQ model used to estimate deposition is based on peer 
reviewed science and represents the best available method for 
predicting Hg deposition in the U.S., (3) evaluated the ability of the 
Mercury Maps-based approach for relating Hg deposition to MeHg in fish 
to capture Hg hotspots and determined that while finer resolution 
deposition modeling might reveal additional areas with elevated 
deposition, the 12 kilometer

[[Page 9316]]

(km) deposition modeling matches well with the watershed size selected 
for the analysis, and thus the use of 12 km deposition estimates with 
the Mercury Maps based approach will not be a large source of 
uncertainty, (4) evaluated the limited coverage that we have with fish 
tissue Hg data for watersheds in the U.S. and implications for the Hg 
Risk TSD and based on the SAB's recommendations, we supplemented the 
coverage of watersheds by obtaining additional fish tissue Hg samples 
for areas heavily impacted by U.S. EGU deposition, thus reducing the 
uncertainty in the analysis, (5) evaluated the uncertainty in the 
preparation factor and determined that the level of uncertainty is low, 
and as such would have minimal impact on the risk estimates, (6) 
evaluated the uncertainty resulting from the proportionality assumption 
used to relate changes in Hg deposition to changes in fish tissue Hg 
levels at the watershed-level, and determined, based both on 
quantitative sensitivity analyses and qualitative assessments, that 
this source of uncertainty is not likely to greatly influence the 
results, and is not likely to have a specific directional bias, (7) 
evaluated the uncertainty related to characterization of the spatial 
locations of subsistence populations and determined that uncertainty 
could be reduced by focusing the risk estimates on female subsistence 
fishing populations, which are assumed to have the potential to fish in 
all watersheds, in response to SAB's concerns regarding potential 
exclusion of watersheds with fewer than 25 individuals and (8) 
evaluated the potential impact of the uncertainty in application of the 
RfD to low SES populations. The EPA determined that due to the method 
used in calculating the RfD, we have confidence that the RfD provides 
protection for low SES populations.
     Expand the sensitivity analyses (over those included in 
the original risk assessment) to address uncertainty related to the use 
of the 75th percentile fish tissue Hg value (at each watershed) as the 
core risk estimate. Based on the SAB's recommendation, we added a 
sensitivity analysis using the median fish tissue Hg estimate (at the 
watershed level). This sensitivity analysis showed that use of the 
median fish tissue Hg concentration instead of the 75th percentile 
resulted in a relatively small decrease (i.e., 10 percent) in the 
estimates of watersheds with populations potentially at-risk, and did 
not substantially change the conclusions of the risk assessment.

C. Summary of Results of Revised Hg Risk TSD of Risks to Populations 
With High Levels of Self-Caught Fish Consumption

    Based on the recommendations we received from the SAB, we revised 
the quantitative analysis of risk to subsistence fishing populations 
with high levels of fish consumption. Our revision to the quantitative 
risk results reflects three key recommendations from the SAB, including 
(1) addition of 824 watersheds based on additional fish tissue Hg 
sample data we obtained from states and the National Listing of Fish 
Advisories, (2) application of a 0.95 adjustment factor to the reported 
fish tissue Hg concentrations to account for the fraction that is MeHg, 
and (3) inclusion of all watersheds with fish samples that meet the 
filtering criteria \34\ in representing potential exposures associated 
with increased risk of neurologic health effects for female subsistence 
fishing populations.
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    \34\ The watersheds were filtered to exclude watersheds that: 
(a) Were not freshwater, (b) did not have fish sampling data since 
2000, (c) did not have fish larger than 7 inches in length, (d) 
contained active gold mines or (e) had substantial non-air Hg 
loading.
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    Based on these revisions, our estimates of the number and percent 
of modeled watersheds with populations potentially at-risk from 
exposure to EGU-attributable MeHg changed from those presented in the 
preamble to the proposed rule.\35\ For the 99th percentile consumption 
scenario, the number of watersheds with fish tissue Hg samples where 
subsistence fishing populations may be at-risk from exposure to EGU-
attributable MeHg increased from 672 to 917 (an increase of 36 
percent). For this same scenario, the total percent of modeled 
watersheds with populations potentially at-risk from either risk metric 
(i.e., MeHg exposure from U.S. EGUs alone exceeds the RfD or total MeHg 
exposure exceeds the RfD and U.S. EGUs contribute at least 5 percent) 
increased from 28 percent estimated at proposal to 29 percent after 
addressing SAB recommendations. The increase in the total percent of 
modeled watersheds with populations potentially at-risk using the 
expanded geographic coverage of watersheds provides additional 
confidence that emissions of Hg from U.S. EGUs pose a hazard to public 
health. For the 99th percentile consumption scenario, the percent of 
modeled watersheds with populations potentially at-risk from total 
potential exposures to MeHg that exceed the RfD and U.S. EGUs 
contribute at least 5 percent increased from 22 percent to 24 percent. 
For the 99th percentile consumption scenario, the percent of modeled 
watersheds with populations potentially at-risk based on Hg deposition 
from U.S. EGUs alone decreased from 12 percent to 10 percent.
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    \35\ Since the time of the analyses conducted in support of the 
proposed rule, the EPA updated IPM modeling to reflect the most 
recently available information, including public comments and the 
final CSAPR (see IPM Documentation for further details on these 
updates, which is available in the docket). Compared to the modeling 
conducted at proposal, these updates are projected to result in 
greater reductions in criteria pollutants, and also to have a 
slightly greater impact on U.S. EGU Hg emissions. Based on the 
revised projection for 2016, the EPA estimates that U.S. EGUs would 
emit 27 tons of Hg, as compared to the 29 tons we modeled for the Hg 
Risk TSD. We do not expect this 2 ton difference to substantially 
change the mercury risks reported in the preamble to the proposed 
rule, as this represents less than a 10 percent reduction in Hg 
emissions.
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    The additional sensitivity analyses conducted in response to the 
SAB peer review showed that the estimates of the percent of modeled 
watersheds with populations potentially at-risk are robust to 
alternative assumptions about both the watersheds included in the 
analysis and the selection of the 50th percentile or 75th percentile 
fish tissue Hg level. Sensitivity analyses excluding entire states with 
the potential for historical loadings of Hg from non-air sources \36\ 
resulted in an increase from 29 percent to 33 percent in the total 
percent of modeled watersheds with populations potentially at-risk 
exceeding either risk metric (i.e., U.S. EGUs alone or total potential 
exposures to MeHg exceed the RfD and U.S. EGUs contribute at least 5 
percent). Including only watersheds in the top 25th percentile of U.S. 
EGU deposition resulted in an increase in the total percent of modeled 
watersheds with populations potentially at-risk exceeding either risk 
metric, from 29 percent to 30 percent. Using the 50th percentile fish 
tissue Hg level resulted in a decrease in the total percent of modeled 
watersheds with populations potentially at-risk exceeding either risk 
metric, from 29 percent to 26 percent. On balance, these sensitivity 
analyses do not substantially reduce the percent of modeled watersheds 
with populations potentially at-risk, and thus confirm the finding that 
Hg emissions from U.S. EGUs pose a hazard to public health. In fact, 
given the broader coverage of modeled watersheds in the revised 
analysis, we have even greater confidence in our finding that Hg

[[Page 9317]]

emissions from U.S. EGUs pose a hazard to public health.
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    \36\ The SAB noted that areas with substantially elevated fish 
tissue Hg levels could also be characterized by lakes and rivers 
with high natural methylation rates, and thus some of the states we 
excluded for this sensitivity analysis might not have fish tissue Hg 
levels that reflect non-U.S. EGU Hg loadings.
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D. Peer Review of the Approach for Estimating Cancer Risks Associated 
With Cr and Ni Emissions in the U.S. EGU Case Studies of Cancer and 
Non-Cancer Inhalation Risks for Non-Hg HAP and EPA Response

    As explained in the preamble to the proposed rule, the EPA 
submitted for peer review its characterization of the chemical 
speciation for the emissions of Cr and Ni used in the non-Hg HAP 
inhalation risk case studies. The remaining aspects of the non-Hg HAP 
case study risk assessments used methods that were previously peer 
reviewed. Specifically, the methodologies used to conduct the non-Hg 
case studies are consistent with those used to conduct inhalation risk 
assessments under EPA's Risk and Technology Review (RTR) program. 
Because the RTR assessments are considered to be highly influential 
science assessments, the methodologies used to conduct them were 
subject to a peer review by the SAB in 2009. The SAB issued its peer 
review report in May 2010.\37\ The report endorsed the risk assessment 
methodologies used in the program, and made a number of technical 
recommendations for EPA to consider as the RTR program evolves.
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    \37\ U.S. Environmental Protection Agency--Science Advisory 
Board (U.S. EPA-SAB). 2010. Review of EPA's draft entitled, ``Risk 
and Technology Review (RTR) Risk Assessment Methodologies: For 
Review by the EPA's Science Advisory Board with Case Studies--MACT I 
Petroleum Refining Sources and Portland Cement Manufacturing''. EPA-
SAB-10-007. May. Available on-line at: http://yosemite.epa.gov/sab/
sabproduct.nsf/4AB3966E263D943A8525771F00668381/$File/EPA-SAB-10-
007-unsigned.pdf.
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    The EPA's case studies identified Cr and Ni emissions as the key 
drivers of the estimated inhalation cancer risks for EGUs. Because 
these results hinged on specific scientific interpretations of data 
used to characterize EGU emissions of Cr and Ni, the EPA conducted a 
letter peer review of its analysis and interpretation of those data 
relative to the quantification of inhalation risks associated with Cr 
and Ni emissions from U.S. EGUs. The following sections describe the 
peer review process, enumerate the peer review charge questions 
presented to the peer review panel, summarize the key recommendations 
from the peer review, and summarize our responses to those 
recommendations.
1. Summary of Peer Review Process
    The EPA asked three independent, external peer reviewers 
representing government, academic and the private sector to review of 
the methods for developing inhalation cancer risk estimates associated 
with emissions of Cr and Ni compounds from coal- and oil-fired EGUs in 
support of the appropriate and necessary finding. The approaches and 
rationale for the technical and scientific considerations used to 
derive inhalation cancer risks were summarized in the draft document 
entitled, ``Methods to Develop Inhalation Cancer Risk Estimates for 
Chromium and Nickel Compounds.'' The peer reviewers received several 
charge questions (three questions on Cr and two questions on Ni, which 
are provided below) on the technical and scientific relevance of the 
approaches used to develop the inhalation unit risk estimates. The EPA 
also provided information on Cr speciation profiles for different 
industrial sources, as well as information on the Ni speciation of PM 
from oil-fired EGUs.
2. Peer Review Charge Questions
    Below, we present the charge questions posed to the peer reviewers 
to help guide their review and development of recommendations to EPA on 
key issues relevant to the characterization of risks from EGU emissions 
containing either Cr or Ni compounds.
    The EPA asked three questions regarding Cr and Cr compounds:
    Question 1: Do EPA's judgments related to speciated Cr emissions 
adequately take into account the available Cr speciation data?
    Question 2: Has EPA selected the species of Cr (i.e., hexavalent 
Cr, Cr(VI)) that accurately represents the toxicity of Cr and Cr 
compounds?
    Question 3: Are the assumptions used in past analysis 
scientifically defensible, and are there alternatives that EPA should 
consider for future analysis?
    The EPA asked two questions regarding Ni and Ni compounds:
    Question 1: Do EPA's judgments related to speciated Ni emissions 
adequately take into account available speciation data, including 
recent industry spectrometry studies?
    Question 2: Based on the speciation information available and on 
what we know about the health effects of Ni and Ni compounds, and 
taking into account the existing Unit Risk Estimates (URE) values 
(i.e., values derived for EPA's Integrated Risk Information System 
(IRIS), California Environmental Protection Agency (Cal EPA) and Texas 
Commission on Environmental Quality (TCEQ)), the EPA has provided 
several approaches \38\ to derive unit risk estimates that may be more 
scientifically defensible than those used in past analyses. Which of 
the options presented would result in more accurate and defensible 
characterization of risks from exposure to Ni and Ni compounds? Are 
there alternative approaches that EPA should consider?
---------------------------------------------------------------------------

    \38\ See section 3.3 of U.S. Environmental Protection Agency 
(U.S. EPA). 2011c. Methods to Develop Inhalation Cancer Risk 
Estimates for Chromium and Nickel Compounds. Office of Air Quality 
Planning and Standards. October.
---------------------------------------------------------------------------

3. Summary of Peer Review Findings and Recommendations
    Regarding Cr and Cr compounds, all three reviewers considered 
Cr(VI) as the species likely to be driving cancer risks based on solid 
evidence from the health effects database for Cr and Cr compounds. All 
three authors also considered EPA's use of the average of the range of 
the available speciation data (i.e., 12 percent and 18 percent Cr(VI) 
contained in coal- and oil-fired EGUs, respectively) as a reasonable 
approach for the derivation of default speciation profiles to be used 
when there is no speciation data available. All reviewers agreed that 
there is high uncertainty associated with the variability in the 
speciation data available for Cr (e.g., range of approximately 4 to 23 
percent Cr(VI) from coal-fired units). One of the reviewers recommended 
several additional studies for EPA's consideration; the EPA considered 
these in finalizing the report.
    Regarding Ni and Ni compounds, the reviewers agreed with the views 
of the international scientific bodies, which consider Ni compounds 
carcinogenic as a group. One reviewer recommended that the EPA review 
several additional Ni speciation data that suggests that sulfidic Ni 
compounds (which the reviewer considered as the most potent carcinogens 
within the group of all Ni compounds) are present at low levels in 
emissions from EGUs. In addition, this reviewer pointed out that there 
is a recently proposed model that may explain the differences in 
carcinogenic potential across Ni compounds.
4. The EPA's Responses to Peer Review Recommendations
    We summarize EPA's basic responses to the peer review comments 
below, first for Cr-related issues, and second for Ni-related issues, 
which are reflected in the revised document.\39\
---------------------------------------------------------------------------

    \39\ U.S. EPA, 2011c.

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[[Page 9318]]

a. Cr and Cr Compounds
    In agreement with the peer reviewers and based on the health 
effects information available for Cr, the EPA assigns high confidence 
in the assumption that Cr(VI) is the carcinogenic species driving the 
risk of Cr-emitting facilities. In agreement with the reviews, the EPA 
considers derivation of default speciation profiles based on the mass 
of Cr(VI) a reasonable approach. As suggested by one of the reviewers, 
the EPA reviewed two potentially relevant studies, one of which showed 
coal combustion emissions containing as much as 43 percent Cr(VI),\40\ 
which suggests that the EPA's quantitative approach could actually 
underestimate Cr(VI) inhalation risks. However, the other study 
reviewed by EPA on speciation of Cr in coal combustion showed Cr(VI) 
percentage levels close to detection limits (i.e., 3 to 5 percent of 
total Cr, which was close to the limit of detection in this study).\41\ 
Thus, the more recent speciation data available is unlikely to reduce 
the uncertainty of the Cr speciation analyses used by EPA as the bases 
for risk characterization analysis.
---------------------------------------------------------------------------

    \40\ Galbreath KC, Zygarlicke CJ. 2004. ``Formation and chemical 
speciation of arsenic-, chromium-, and nickel-bearing coal 
combustion PM2.5,'' Fuel Process Technol 85:701-726.
    \41\ Huggins FE, Najih M, Huffman GP. 1999. ``Direct speciation 
of chromium in coal combustion by-products by X-ray absorption fine 
structure spectroscopy,'' Fuel Process Technol 78:233-242.
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    In agreement with the peer reviewers, the EPA also recognizes that 
the confidence in the default speciation profiles is low because the 
profiles are based on a limited data set with a wide range of 
percentages of Cr(VI) across the different samples.
b. Ni and Ni Compounds
    Based on the views of the major scientific bodies mentioned above 
and the peer reviewers that commented on EPA's approaches to risk 
characterization of Ni compounds, the EPA considers all Ni compounds to 
be carcinogenic as a group and the EPA does not consider Ni speciation 
or Ni solubility to be strong determinants of Ni carcinogenicity. These 
scientific bodies also recognize that based on the data available, the 
precise Ni compound(s) responsible for the carcinogenic effects in 
humans is not always clear, and that there may be differences in the 
potential toxicity and carcinogenic potential across Ni compounds. 
Nevertheless, studies in humans indicate that various mixtures of Ni 
compounds (including Ni sulfate, sulfides and oxides, alone or in 
combination) encountered in the Ni refining industries may cause cancer 
in humans, and there is no reason to expect anything different from 
this for mixtures of Ni compounds from other emission sources. One of 
the reviewers suggested we consider views by some authors that believe 
that water soluble Ni, such as Ni sulfate, should not be considered a 
human carcinogen. This view is based primarily on a negative Ni sulfate 
2-year rodent bioassay by the National Toxicology Program (NTP) (which 
is different from the positive 2-year NTP bioassay for Ni 
subsulfide).42 43 44 One review article identifies the 
discrepancies between the animal and human data (i.e., from studies of 
cancers in workers inhaling certain forms of Ni versus inhalation 
studies suggesting different carcinogenic potential in rodents with 
different Ni compounds) and states that the epidemiological data 
available clearly support an association between Ni and increased 
cancer risk, although the article acknowledges that the data are 
weakest regarding water soluble Ni. In addition, the EPA identified a 
recent review \45\ that highlights the robustness and consistency of 
the epidemiological evidence across several decades showing 
associations between exposure to Ni and Ni compounds (including Ni 
sulfate) and cancer.
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    \42\ Oller A. 2002. ``Respiratory carcinogenicity assessment of 
soluble nickel compounds.'' Environ Health Perspect. 110:841-844.
    \43\ Heller JG, Thornhill PG, Conard BR. 2009. ``New views on 
the hypothesis of respiratory cancer risk from soluble nickel 
exposure; and reconsideration of this risk's historical sources in 
nickel refineries.'' J Occup Med Toxicol. 4:23.
    \44\ Goodman JE, Prueitt RL, Thakali S, and Oller AR. 2011. 
``The nickel iron bioavailability model of the carcinogenic 
potential of nickel-containing substances in the lung.'' Crit Rev 
Toxicol 41:142-174.
    \45\ Grimsrud TK and Andersen A. ``Evidence of carcinogenicity 
in humans of water-soluble nickel salts.'' J Occup Med Toxicol. 
2010. 5:1-7. Available online at http://www.ossup-med.com/content/5/1/7.
---------------------------------------------------------------------------

    Regarding the second charge question on Ni compounds, two reviewers 
suggested using the URE derived by the TCEQ \46\ for all Ni compounds 
as a group, rather than the one derived by the Integrated Risk 
Information System (IRIS, 1991) \47\ specifically for Ni subsulfide. 
The third reviewer did not comment on an alternative approach. 
Considering this, to develop our primary risk estimate, the EPA decided 
to use a health protective approach by applying 100 percent of the 
current IRIS URE for Ni subsulfide, rather than assuming that 65 
percent of the total mass of emitted Ni might be Ni subsulfide, as used 
in previous analyses. We used the IRIS URE value because IRIS values 
are preferred given the conceptual consistency with EPA risk assessment 
guidelines and the level of peer review that such values receive. We 
used 100 percent of the IRIS value because of the concerns about the 
potential carcinogenicity of all forms of Ni raised by the major 
national and international scientific bodies, and recommendations of 
the peer reviewers. Nevertheless, taking into account that there are 
potential differences in toxicity and/or carcinogenic potential across 
the different Ni compounds, and given that two URE values have been 
derived for exposure to mixtures of Ni compounds that are two to three 
fold lower than the IRIS URE for Ni subsulfide, the EPA also considers 
it reasonable to use a value that is 50 percent of the IRIS URE for Ni 
subsulfide for providing an estimate of the lower end of a plausible 
range of cancer potency values for different mixtures of Ni compounds.
---------------------------------------------------------------------------

    \46\ Texas Commission on Environmental Quality (TCEQ). 2011. 
Development Support Document for nickel and inorganic nickel 
compounds. Available online at http://www.tceq.state.tx.us/assets/public/implementation/tox/dsd/final/june11/nickel_&_compounds.pdf.
    \47\ U.S. EPA, 1991. Integrated Risk Information Service (IRIS) 
assessment for nickel subsulfide. Available at: http://www.epa.gov/iris/subst/0273.htm.
---------------------------------------------------------------------------

    Although this report focused primarily on cancer risks associated 
with emissions containing Ni compounds, it is important to note that 
comparative quantitative analyses of non-cancer toxicity of Ni 
compounds indicate that Ni sulfate is as toxic or more toxic than Ni 
subsulfide or Ni oxide which does not support the notion that the 
solubility of Ni compounds is a strong determinant of its 
toxicity.48 49
---------------------------------------------------------------------------

    \48\ Haber LT, Allen BC, Kimmel CA. 1998. ``Non-Cancer Risk 
Assessment for Nickel Compounds: Issues Associated with Dose-
Response Modeling of Inhalation and Oral Exposures.'' Toxicol Sci. 
43:213-229.
    \49\ National Toxicology Program (NTP). 1996. Technical Report 
Series No. 454, Toxicology and carcinogenesis studies of nickel 
sulfate hexahydrate. July. Available online at http://ntp.niehs.nih.gov/ntp/htdocs/LT_rpts/tr454.pdf.
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E. Summary of Results of Revised U.S. EGU Case Studies of Cancer and 
Non-Cancer Inhalation Risks for Non-Hg HAP

    Based on the results of the peer review and public comments on the 
non-Hg case study chronic inhalation risk assessment, we made several 
changes to the emissions estimates, dispersion modeling, and risk 
characterization for the modeled case study facilities. Key changes 
include (1) changes in emissions, (2) changes in stack parameters for 
some facilities based on new data received during the

[[Page 9319]]

public comment period, (3) use of updated versions of AERMOD and its 
input processors (AERMAP, AERMINUTE, and AERMET), and (4) use of 100 
percent of the current IRIS URE for Ni subsulfide to calculate Ni-
associated inhalation cancer risks (rather than assuming that the Ni 
might be 65 percent as potent as Ni subsulfide).
    Based on estimated actual emissions, the highest estimated 
individual lifetime cancer risk from any of the 16 case study 
facilities was 20 in a million, driven by Ni emissions from the one 
case study facility with oil-fired EGUs. Of the facilities with coal-
fired EGUs, five facilities had maximum individual cancer risks greater 
than one in a million \50\ (the highest was five in a million), with 
the risk from four due to emissions of Cr(VI) and the risk from one due 
to emissions of Ni.\51\ There were also two facilities with coal-fired 
EGUs that had maximum individual cancer risks equal to one in a 
million. All of the facilities had non-cancer Target Organ Specific 
Hazard Index (TOSHI) \52\ values less than one, with a maximum TOSHI 
value of 0.4 (also driven by Ni emissions from the one case study 
facility with oil-fired EGUs).
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    \50\ A risk level of 1 in a million implies a likelihood that up 
to one person, out of one million equally exposed people would 
contract cancer if exposed continuously (24 hours per day) to the 
specific concentration over 70 years (an assumed lifetime). This 
would be in addition to those cancer cases that would normally occur 
in an unexposed population of one million people.
    \51\ When the lower end of the cancer potency range for Ni was 
used to develop risk estimates, 5 of the 16 facilities had maximum 
cancer risks exceeding 1 in a million, and the maximum individual 
cancer risk for any single facility fell to 10 in a million.
    \52\ The target-organ-specific hazard index (TOSHI) is a metric 
used to assess whether there is an appreciable risk of deleterious 
(noncancer) effects to a specific target organ due to continuous 
inhalation exposures over a lifetime. If a TOSHI value is less than 
or equal to one, such effects are unlikely. For TOSHI values greater 
than one, there is an increased risk of such effects.
---------------------------------------------------------------------------

    Since these case studies do not cover all facilities in the 
category, and since our assessment does not include the potential for 
impacts from different EGU facilities to overlap one another (i.e., 
these case studies only look at facilities in isolation), the maximum 
risk estimates from the case studies likely underestimates true maximum 
risks for the source category.
    Based on the fact that six U.S. EGUs were estimated to meet or 
exceed the CAA section 112(c)(9) criterion of one in a million, EGUs 
cannot be removed from the list of source categories to be regulated 
under CAA section 112.

F. Public Comments and Responses to the Appropriate and Necessary 
Finding

1. Legal Aspects of Appropriate and Necessary Finding
a. History of Section 112(n)(1)(A)
    Comment: One commenter provided a detailed history of EPA's 
regulatory actions concerning EGUs and implementation of CAA section 
112(n)(1)(A). The same commenter implies that the EPA's 2000 
appropriate and necessary finding and listing of EGUs was flawed 
because the Agency did not comply with CAA section 307(d) rulemaking 
process. The commenter sought review of the 2000 notice in the U.S. 
Court of Appeals for the District of Columbia Circuit, which was 
dismissed by the D.C. Circuit. Utility Air Regulatory Group v. EPA, No. 
01-1074 (D.C. Cir. July 26, 2001). The commenter then characterizes at 
length the 2005 EPA action that revised the interpretation of CAA 
section 112(n)(1)(A) and, which the D.C. Circuit concluded illegally 
removed EGUs from the CAA section 112(c) list of sources that must be 
regulated under CAA section 112. See New Jersey v. EPA, 517 F.3d 574 
(D.C. Cir. 2008). The commenter notes that the D.C. Circuit did not 
rule on the legal correctness or the sufficiency of the factual record 
supporting EPA's 2000 listing decision or on the factual correctness of 
EPA's later decision to reverse its CAA section 112(n)(1)(A) 
determination. The commenter noted further that the D.C. Circuit 
indicated that the listing decision could be challenged when the Agency 
issued the final CAA section 112(d) standards pursuant to CAA section 
112(e)(4). The commenter concluded by asserting that the Agency could 
not ignore the history associated with the regulation of EGUs under 
section 112 and that two earlier dockets--Docket ID. No. A-92-55 and 
Docket ID. No. EPA-HQ-OAR-2002-0056--are also part of this long 
rulemaking effort and must be accounted for in conjunction with Docket 
No. EPA-HQ-OAR-2009-0234 if all pertinent material and comments are to 
be part of the rulemaking record.
    Response: The commenter characterizes the regulatory history of the 
rule EPA proposed on May 3, 2011. To the extent that characterization 
is inconsistent with the lengthy regulatory history EPA provided in the 
preamble to the May 3, 2011 rule, we disagree. We address several of 
the statements in more detail below.
    First, the commenter makes much of the fact that the EPA did not go 
through CAA section 307(d) notice and comment rulemaking when making 
the appropriate and necessary finding and listing decision in 2000. 
However, the commenter's complaint is without foundation. The CAA does 
not require CAA section 307(d) rulemaking for listing decisions. In 
fact, CAA section 112(e)(4) specifically provides that listing 
decisions may only be challenged ``when the Administrator issues 
emission standards for such * * * [listed] category.'' Second, the 
commenter challenged the listing decision in the U.S. Court of Appeals 
for the District of Columbia Circuit (Court) and, on July 26, 2001, the 
Court granted EPA's motion to dismiss that action based on the plain 
language of CAA section 112(e)(4). Moreover, in addition to the 2000 
notice, the EPA clearly articulated its basis for listing EGUs in this 
proposed rule, which is consistent with CAA section 307(d), and the 
commenter was provided an ample opportunity to comment. Finally, the 
commenter asserts that the rulemaking docket for this action is 
incomplete because the Agency did not include two earlier dockets--
Docket ID. No. A-92-55 and Docket ID. No. EPA-HQ-OAR-2002-0056--for the 
Section 112(n) Revision Rule, 70 FR 15994 (March 29, 2005), and the 
reconsideration of the Section 112(n) Revision Rule, 71 FR 33388 (June 
9, 2006), respectively. The commenter is incorrect because EPA 
incorporated by reference the two dockets at issue. See EPA-HQ-OAR-
2009-0234-3056.
    Comment: One commenter stated that the EPA has assessed the public 
health risks posed by HAP emissions from coal- and oil-fired EGUs for 
the last 40 years. According to the commenter, throughout that time, 
the EPA has come to a single repeated conclusion that HAP emissions 
from EGUs pose little or no risk to public health. Based on this 
conclusion, the EPA has properly chosen not to require EGUs to install 
expensive, new pollution control equipment to control HAP emissions. 
The commenter asserts that, in this proposed rule, the EPA shifts its 
opinion on the health impacts of EGU HAP emissions 180 degrees and now 
seeks to impose sweeping regulatory requirements on all power plants. 
According to the commenter, the EPA's newfound concern about HAP 
emissions from EGUs is not based on new and different assessments of 
the public health consequences of EGU HAP emissions but instead on 
health benefits from the reduction of non-hazardous air pollutants, 
primarily PM, which the Agency is required to regulate under other 
provisions of the CAA. One

[[Page 9320]]

commenter stated that for decades, the EPA set primary ambient air 
quality standards that protect public health with an adequate margin of 
safety, CAA section 109(b)(1), and set secondary standards that are 
[sic] ``requisite to protect the public welfare from any known or 
anticipated adverse effects associated with the presence of such air 
pollutant in the ambient air,'' CAA 109(b)(2). The commenter notes that 
even if EPA now views those past PM standards as inadequate, the EPA 
has ongoing regulatory proceedings in which it can address any 
perceived health concerns. The commenter concludes that regulation of 
EGU HAP emissions under CAA section 112 is an unlawful way to address 
those concerns.
    Response: The commenter is incorrect in its assertion that the 
Agency has consistently concluded that HAP emissions from EGUs do not 
present a hazard to public health. In the 2000 finding, the Agency 
concluded that HAP emissions from coal- and oil-fired EGUs do pose a 
hazard to public health and determined that it was appropriate and 
necessary to regulate such units under CAA section 112. As a result of 
that finding, the EPA added coal- and oil-fired EGUs to the CAA section 
112(c) list of source categories for which emission standards are to be 
established pursuant to CAA section 112(d). Further, in support of the 
proposed rule, the EPA conducted additional extensive quantitative and 
qualitative analyses, which confirm that it remains appropriate and 
necessary to regulate EGUs under CAA section 112. Among other things, 
those analyses demonstrate that emissions from coal- and oil-fired EGUs 
continue to pose a hazard to public health. The commenter also fails to 
note that the EPA found that HAP emissions from EGUs pose a hazard to 
the environment as well.
    The commenter seems confused about the basis for the Agency's 
appropriate and necessary finding because it maintains that the EPA 
made the appropriate and necessary finding based on the health co-
benefits attributable to PM reductions that will be achieved as a 
result of the Agency's regulation of HAP emissions from EGUs. Nowhere 
in the May 2011 proposal does EPA state that it based the appropriate 
and necessary finding on hazards to public health attributable to PM 
emissions. The commenter's allegation lacks foundation. The appropriate 
and necessary finding unmistakably focuses on the hazards to public 
health and hazards to the environment associated with HAP emissions 
from EGUs.
    Comment: One commenter stated that CAA section 112 required EPA to 
make a risk-based determination in order to regulate HAP. According to 
the commenter, the EPA may regulate substances ``reasonably * * * 
anticipated to result in an increase in mortality or increase in 
serious illness'' to a level that protects public health with an 
``ample margin of safety.'' According to the commenter, the EPA has 
regulated a number of HAP emitted from industrial source categories 
other than EGUs.
    As for EGUs, according to the commenter, the EPA found that the 
combustion of fossil fuels produces extremely small emissions of a 
broad variety of substances that are present in trace amounts in fuels 
and that are removed from the gas stream by control equipment installed 
to satisfy other CAA requirements. The commenter stated that the EPA, 
in past reviews, found that these HAP emissions did not pose hazards to 
public health. See 48 FR 15076, 15085 (1983) (radionuclides). the 
commenter further stated that ``[i]n the case of Hg specifically, the 
EPA found that ``coal-fired power plants * * * do not emit mercury in 
such quantities that they are likely to cause ambient mercury 
concentration to exceed'' a level that ``will protect public health 
with an ample margin of safety.'' 40 FR 48297-98 (October 19, 1975) 
(Hg); 52 FR 8724, 8725 (March. 19, 1987) (reaffirming Hg conclusion).
    According to the commenter, in the late 1980s, the EPA was 
concerned that its prior risk assessments of individual HAP emissions 
from fossil-fuel-fired power plants may not reflect the total risks 
posed by all HAP emitted by those sources. The commenter states that 
the EPA modeled the risks posed by all HAP emitted by power plants 
(very much like the analyses the Agency would conduct for the Utility 
Study ten years later). The commenter asserts that the modeling again 
failed to identify threats to public health that warranted regulation 
under an ``ample margin of safety'' test.
    Response: The commenter's statements concerning the pre-1990 CAA 
are not relevant to the current action. Congress enacted CAA section 
112(n)(1) as part of the 1990 amendments to the Act. That provision 
requires, among other things, that the Agency evaluate the hazards to 
public health posed by HAP emissions from fossil-fuel fired EGUs. Had 
Congress concluded, as commenter appears to assert, that HAP emissions 
from EGUs did not pose a hazard to public health or the environment, it 
defies reason that Congress would have required EPA to conduct the 
three studies at issue in CAA section 112(n)(1) (titled ``Electric 
utility steam generating units'') and regulate EGUs under section 112 
if the Administrator determined in her discretion that it was 
appropriate and necessary to do so. The Agency complied with the 
statutory mandates in CAA section 112(n)(1) in conducting the studies 
and reasonably exercised its discretion in making the appropriate and 
necessary finding.
    We acknowledge that Congress treated radionuclide emissions from 
EGUs differently. For radionuclides from EGUs (and certain other 
sources), Congress included CAA section 112(q)(3), which authorizes but 
does not require the Agency to maintain the regulations of 
radionuclides in effect prior to the 1990 amendments. The fact that 
Congress made an exception for radionuclides and no other HAP from EGUs 
further demonstrates that the HAP-related actions EPA took with regard 
to EGUs prior to the 1990 amendments to the CAA are not germane.
    As for the commenter's statements about Hg emissions from EGUs, we 
find their conclusions wholly inconsistent with CAA section 112(n)(1). 
That provision is titled ``Electric utility steam generating units,'' 
and it directs EPA to conduct two Hg-specific studies. See CAA sections 
112(n)(1)(B) and 112(n)(1)(C). The commenter's suggestion that the EPA 
could or should rely on assessments of Hg from EGUs conducted prior to 
the 1990 amendments is not tenable.
    Finally, the commenter stated that the EPA conducted a risk 
assessment of all HAP from EGUs prior to the 1990 amendments and that 
the Agency did not identify any HAP that failed the ``ample margin of 
safety'' test. The commenter did not cite the study or provide any 
information to support the statements so we are unable to respond to 
the alleged study directly; however, the risk assessments conducted in 
support of the appropriate and necessary finding, as well as the 2000 
finding, demonstrate that HAP emissions from EGUs pose hazards to 
public health and the environment.
b. Interpretation of ``Appropriate'' and ``Necessary''
    Comment: One commenter stated that in the preamble to the proposed 
rule, the EPA sets out its ``interpretation of the critical terms in 
CAA section 112(n)(1),'' arguing that this latest interpretation is 
``wholly consistent with the CAA'' and with the Agency's earlier ``2000 
finding.'' See 76 FR 24976, 24986 (May 3, 2011). The commenter stated 
that throughout the proposal EPA tries to suggest that it is returning 
to

[[Page 9321]]

some earlier, ``correct'' interpretation of CAA section 112(n)(1) set 
forth in its 2000 action. See, e.g., 76 FR 24989 (``The Agency's 
interpretation of the term `appropriate' * * * is wholly consistent 
with the Agency's appropriate finding in 2000''); id. at 24992 (``Our 
interpretation of the necessary finding is reasonable and consistent 
with the 2000 finding''). According to the commenter, the EPA did not 
provide in 2000 any interpretation of what it now characterizes as the 
``critical terms'' of section 112(n)(1). See, e.g., 70 FR 15999 n.13 
(the ``2000 finding does not provide an interpretation of the phrase 
`after imposition of the requirements of the Act' ''); id. at 16000/2 
(in 2000, the EPA ``did not provide an interpretation of the term 
`appropriate' ''); 76 FR 24992 (the ``Agency did not expressly 
interpret the term necessary in the 2000 finding''). The commenter 
believes that for that reason alone, it is impossible to credit EPA's 
assertion that it ``appropriately concluded that it was appropriate and 
necessary to regulate hazardous air pollutants * * * from EGUs'' in 
2000, and that it is today merely ``confirm[ing] that finding and 
conclud[ing] that it remains appropriate and necessary to regulate 
these emissions.* * *'' \53\
---------------------------------------------------------------------------

    \53\ Id. at 24,977/3.
---------------------------------------------------------------------------

    Response: The commenter disagrees with certain statements in the 
preamble to the proposed rule that provide that the Agency's 
interpretation of CAA section 112(n)(1) is reasonable and consistent 
with the 2000 finding. It is difficult to decipher the exact complaint 
that the commenter has with EPA's proposed rule in this regard, but the 
commenter does assert that ``the Agency did not provide in 2000 any 
interpretation of what it now characterizes as the ``critical terms'' 
of CAA section 112(n)(1).'' The commenter's assertion lacks foundation. 
Although the 2000 finding did not provide detailed interpretations of 
the regulatory terms at issue, it discussed the types of considerations 
relevant to the appropriate and necessary inquiry. For example, it is 
clear that in 2000, the Agency was concerned with the then current 
hazards to public health and the environment when assessing whether it 
was appropriate to regulate EGUs under section 112.\54\ In addition, 
when evaluating whether it was necessary to regulate utilities, the 
Agency stated that it was necessary to regulate HAP emissions from U.S. 
EGUs under section 112 because the implementation of the other 
requirements of the Act would not adequately address the serious public 
health and environmental hazards arising from HAP emissions from EGUs. 
The Agency also specifically noted that ``section 112 is the authority 
intended to address'' hazards to public health and the environment 
posed by HAP emissions. Id.
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    \54\ 65 FR 79830.
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    The detailed interpretation set forth in the preamble to the 
proposed rule is consistent with the 2000 finding, but EPA does not 
assert that the interpretation is in any way necessary to support the 
factual conclusions reached in the 2000 finding. Instead, we noted in 
the preamble to the proposed rule that our interpretation is consistent 
with the 2000 finding because in 2005 we interpreted the statute in a 
manner that was not consistent with the 2000 finding. The commenter has 
provided no legal support for its position that the Agency erred in 
interpreting the statute in a manner that is consistent with a prior 
factual finding.
    Comment: Several commenters assert that in the 1990 amendments to 
the Clean Air Act, Congress directed the EPA to base its determination 
regarding regulation of fossil-fuel-fired generating units on 
consideration of any adverse public health effects identified in the 
study mandated by the first sentence of section 112(n)(1)(A) and that 
Congress did not dictate in section 112(n)(1)(A) that the EPA must 
regulate electric utility steam generating units under section 112.
    According to the commenters the sponsor of the House bill that 
became section 112(n)(1)(A) provides an explanation that contradicts 
the EPA's approach to regulating EGUs:

    Pursuant to section 112(n), the Administrator may regulate 
fossil fuel fired electric utility steam generating units only if 
the studies described in section 112(n) clearly establish that 
emissions of any pollutant, or aggregate of pollutants, from such 
units cause a significant risk of serious adverse effects on the 
public health. Thus, * * * he may regulate only those units that he 
determines--after taking into account compliance with all provisions 
of the act and any other Federal, State, or local regulation and 
voluntary emission reductions--have been demonstrated to cause a 
significant threat of serious adverse effects on the public health.

136 Cong. Rec. H12,934 (daily ed. Oct. 26, 1990) (statement of Rep. 
Michael Oxley).

    The commenters stated that the EPA position is premised on the 
assumption that ``regulation under section 112'' necessarily means 
``regulation under 112(d)'' and falsely premised on the assumption that 
source categories listed by operation of section 112(n)(1)(A) cannot be 
regulated differently. The commenters conclude that the language of 
section 112(n)(1)(a) reflects Congress' intent that ``regulation of HAP 
from EGUs was not intended to operate under section 112(d) but was 
instead intended to be tailored to the findings of the utility study 
mandated by section 112(n)(1)(A).''
    Response: The commenters maintain that the Agency's interpretation 
of CAA section 112(n)(1) is flawed in many respects. The primary 
support for one commenter's arguments against EPA's interpretation, 
including in the comment above, is legislative history in the form of 
statements from one Congressman, Representative Oxley. The Supreme 
Court has repeatedly stated that the statements of one legislator alone 
should not be given much weight. See Brock v. Pierce County, 476 U.S. 
253, 263 (1986) (finding that ``statements by individual legislators 
should not be given controlling effect, but when they are consistent 
with the statutory language and other legislative history, they provide 
evidence of Congress' intent.'') (emphasis added) (citation omitted); 
Garcia, et al., v. U.S., 469 U.S. 70, 78 (1984), citing Zuber v. Allen, 
396 U.S. 168, 187 (1969) (reiterating its prior findings, the Court 
indicated that isolated statements ``are `not impressive legislative 
history.' ''); Weinberger, et al., v. Rossi et al., 456 U.S. 25, 35 
(declining to make a ruling based on ``one isolated remark by a single 
Senator''); Consumer Product Safety Comm., et al. v. GTE Sylvania, 
Inc., et al., 447 U.S. 102, 117-118 (1980) (declining to give much 
weight to isolated remarks of one Representative); Chrysler Corp. v. 
Brown, et al., 441 U.S. 281, 311 (1979) (finding that ``[t]he remarks 
of a single legislator, even the sponsor, are not controlling in 
analyzing legislative history.''); Zuber, 396 U.S. at 186 (concluding 
that ``[f]loor debates reflect at best the understanding of individual 
Congressmen.''); and U.S. v. O'Brien, 391 U.S. 367, 384 (1968) (in 
evaluating the statements of a handful of Congressmen, the Court 
concluded that ``[w]hat motivates one legislator to make a speech about 
a statute is not necessarily what motivates scores of others to enact 
it. * * *.''). As these cases show, the Supreme Court does not give 
weight to the statements of an individual legislator, except when the 
statements are supported by other legislative history and the clear 
intent of the statute. The commenters cited no case law that would 
support reliance on such limited legislative history.
    The commenter has not cited any other legislative history to 
support

[[Page 9322]]

Representative Oxley's statement, and the lack of additional support 
makes the statement of little utility or import under the case law. In 
fact, there does not appear to be anything in the House, Senate, or 
Committee Reports that supports Oxley's statement. The lack of support 
for Oxley's statement in the Committee Report is particularly telling 
since, as the commenter notes, the House and Senate bills required 
different approaches to regulating EGUs under section 112, with the 
Senate bill requiring EGUs be regulated prior to the Utility Study. In 
fact, legislative statements from Senator Durenberger, a supporter of 
the Senate version, demonstrate that others would almost certainly not 
have agreed with Oxley's interpretation. For example, Senator 
Durenberger stated, ``It seems to me inequitable to impose a regulatory 
regime on every industry in America and then exempt one category, 
especially a category like power plants which are a significant part of 
the air toxics problem.''
    Senator Durenberger discussed the negotiations with the 
Administration and the industry push to avoid regulation, including 
industry arguments for not regulating Hg from U.S. EGUs:

    The utility industry continued to adamantly oppose [regulation 
under section 112]. First, they argued that mercury isn't much of an 
environmental problem. But as the evidence mounted over the summer 
and it became clear that mercury is a substantial threat to the 
health of our lakes, rivers and estuaries and that power plants are 
among the principal culprits, they changed their tactic. Now they 
are arguing that mercury is a global problem so severe that just 
cleaning up U.S. power plants won't make enough of a difference to 
be worth it. They've gone from `we're not a problem' to `you can't 
regulate us until you address the whole global problem.' Recasting 
an issue that way is not new around here. So, it is not a surprise. 
But it does suggest the direction in which this debate will be 
heading in the next few years.

136 Cong. Rec. 36062 (October 27, 1990).

    Senator Durenberger also explained why the House version was 
adopted:

    Given that a resolution of the difficult issues in the 
conference were necessary to conclude work on this bill, the Senate 
proposed to recede to the House provision which was taken from the 
original administration bill. It provides for a 3-year study of 
utility emissions followed by regulation to the extent that the 
Administrator finds them necessary.

Id.

    Senator Durenberger's statements indicate that it is unlikely that 
he would agree with Oxley's interpretation of CAA section 112(n)(1), a 
provision that provides the Agency with considerable discretion, and 
nothing indicates that others in the Senate (or for that matter anyone 
else in the House) would agree with that interpretation. Given the 
Supreme Court's views on the use of such limited legislative history, 
the EPA reasonably declined to consider (or even discuss) the 
legislative history in the preamble to the proposed rule and we believe 
it would be improper to ascribe Representative Oxley's statements to 
the entire Congress.
    Moreover, Representative Oxley's statement directly conflicts with 
the statutory text. Representative Oxley stated that ``[the 
Administrator may regulate only those units that he determines--after 
taking into account compliance with all provisions of the act and any 
other Federal, State, or local regulation and voluntary emission 
reductions--have been demonstrated to cause a significant threat of 
serious adverse effects on the public health.'' 136 Cong. Rec. H12934 
(daily ed. Oct. 26, 1990), reprinted in 1 1990 Legis. Hist. at 1416-17 
(emphasis added). However, the Utility Study required under CAA section 
112(n)(1)(A) directs the Agency to consider the hazards to public 
health reasonably anticipated to occur after ``imposition of the 
requirements of [the Clean Air Act].'' EPA was not required to consider 
state or local regulations or voluntary emission reduction programs in 
the Utility Study, and that study is the only condition precedent to 
making the appropriate and necessary finding.\55\
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    \55\ In addition, the EPA only considered CAA requirements in 
the Utility Study and this was the correct approach because Congress 
knew how to require consideration of non-Federal requirements when 
directing EPA to conduct a study or assessment. See CAA section 
112(n)(5) (Congress required EPA to conduct an assessment of 
hydrogen sulfide from oil and gas extraction activities and provided 
that the assessment ``shall include review of existing State and 
industry control standards, techniques and enforcement.'').
---------------------------------------------------------------------------

    The legislative history the commenters rely on is not controlling. 
The Agency believes that it has reasonably interpreted section 
112(n)(1)(A), for all the reasons described herein and in the proposal. 
The commenters also cite Representative Oxley's statements as support 
for alternative interpretations of CAA section 112(n)(1). We believe 
that any arguments that rely on such limited legislative history are 
without merit.
    Comment: One commenter stated that the EPA does acknowledge that, 
in many significant respects, its new interpretation of CAA section 
112(n)(1) ``differs from that set forth'' in the Agency's 2005 
rulemaking, but argues that its change of position is permissible. See 
76 FR 24988/1 (``[T]o the extent our interpretation differs from that 
set forth in the 2005 Action, we explain the basis for that difference 
and why the interpretation, as set forth in this preamble, is 
reasonable.''). In support, commenters note that the EPA cites National 
Cable & Telecommunication Ass'n v. Brand X Internet Services, 545 U.S. 
967 (2005). The commenters agree that it is true that, in Brand X 
Internet Services, the Supreme Court explained that, if an agency 
``adequately explains the reasons for a reversal of policy,'' such 
change is ``not invalidating,'' since the ``whole point of Chevron is 
to leave the discretion provided by the ambiguities of a statute with 
the implementing agency.'' 545 U.S. at 981 (internal quotations 
omitted). The commenters maintain that all Brand X Internet Services 
was saying is that ``[a]gency inconsistency is not a basis for 
declining to analyze the agency's interpretation under the Chevron 
framework.'' Id.
    According to the commenter, it is not enough that the EPA has 
purported to ``explain'' why it has abandoned the interpretation of CAA 
section 112(n)(1) adopted in 2005. The commenter states that under the 
first step of Chevron, the Agency's latest interpretation must still be 
consistent with congressional intent. See Chevron v. NRDC, 467 U.S. at 
842-43. The commenters state that under the second step of Chevron, if 
there is discretion for EPA to exercise in interpreting the ``critical 
terms'' of CAA section 112(n)(1), the Agency must properly define the 
range of that discretion and then act reasonably in exercising that 
discretion. See Chevron, 467 U.S. at 843; see also Village of 
Barrington, Ill. v. Surface Transportation Bd., No. 09-1002 (D.C. Cir. 
Mar. 15, 2011).The commenters allege that the EPA failed to properly 
define and exercise the scope of its discretion. In each instance, the 
commenter maintains that the Agency has departed from the correct 
interpretation of CAA section 112(n)(1) that it adopted in 2005, 
seizing instead upon a new approach that is contrary to the plain 
language of the CAA itself, as interpreted after considering the 
statements of Representative Oxley.
    Response: The commenter appears to argue that the EPA's 
interpretation of CAA section 112(n)(1) is not consistent with the 
plain language of the statute, implying that the statute is clear and 
must be evaluated under step one of Chevron. See Chevron v. NRDC, 467 
U.S. 837 842-42 (1984) (finding that when the legislative intent is 
clear no additional analysis is required).

[[Page 9323]]

However, as noted above, much of the commenter's argument that the 
plain language of the statute precludes EPA's interpretation is based 
on the unpersuasive legislative history discussed above. As explained 
in the preamble to the proposed rule, the statute directs the Agency to 
determine whether it is appropriate and necessary to regulate EGUs 
under section 112. As the D.C. Circuit has held, the terms 
``appropriate'' and ``necessary'' are very broad terms. Because these 
terms are broad they are susceptible to different interpretations. We 
believe we have reasonably interpreted the appropriate and necessary 
language in section 112(n)(1)(A). To the extent that interpretation 
differs from the one set forth in 2005, we have fully explained the 
basis for such changes. See 76 FR 24986-24993 (setting forth the 
Agency's interpretation of section 112(n)(1)).
    Furthermore, we properly considered the scope of our discretion in 
interpreting the statute as explained in detail in the preamble to the 
proposed rule. We believe the interpretation set forth in the preamble 
to the proposed rule is consistent with the Act and, therefore, the 
Agency should be afforded deference pursuant to National Cable & 
Telecommunication Ass'n v. Brand X Internet Services, 545 U.S. 967 
(2005).
    Comment: A number of commenters agreed with the Agency's 
interpretation of section 112(n)(1) and the terms appropriate and 
necessary. The commenters also agreed that the EPA's interpretation of 
that provision was reasonable and consistent with the statute.
    Response: We agree with the commenters and appreciate their 
support.
    Comment: One commenter asserts that the EPA's ultimate motivation 
for rejecting its prior interpretation of CAA section 112(n)(1) and 
embracing this flawed new approach is made clear from the very outset 
of the proposal. According to the commenter, the EPA touts the fact 
that ``one consequence'' of the MACT rule would be that the ``market 
for electricity in the U.S. will be more level'' and ``no longer skewed 
in favor of the higher polluting units that were exempted from the CAA 
at its inception on Congress' assumption that their useful life was 
near an end.'' See 76 FR 24979/2. The MACT rule would ``require 
companies to make a decision--control HAP emissions from virtually 
uncontrolled sources'' or else ``retire these sometimes 60 year old 
units and shift their emphasis to more efficient, cleaner modern 
methods of generation, including modern coal-fired generation.'' Id.
    The commenter stated that this remarkably forthright statement 
establishes that the underlying basis for EPA's proposal to regulate 
EGUs under CAA section 112 is not to address any ``hazards to public 
health'' that might be attributed to the emission by EGUs of HAP listed 
under CAA section 112(b). Rather, according to commenter, the EPA is 
utilizing the regulation of EGUs under CAA section 112 as a means to an 
entirely different end: To force the imposition of controls that will 
also have the result of reducing non-HAP emissions (primarily PM) or 
force the shutdown of those units for which the cost of such controls 
would be prohibitive. At the same time, according to commenter, the EPA 
tacitly acknowledges that it cannot hope to make out a case that the 
regulation of EGU HAP emissions is ``appropriate and necessary'' within 
the meaning of CAA section 112(n)(1). The commenter asserts that the 
only HAP whose health-related benefits EPA quantifies is Hg. Elsewhere, 
the commenter stated that the EPA contends there are ``additional 
health and environmental effects'' attributable to HAP other than Hg, 
but admits that it has ``not quantified'' those risks due supposedly to 
``insufficient information.'' See 76 FR 24999/2. With respect to Hg the 
commenter stated that the benefits are so questionable and miniscule, 
some $4 million to $6 million (given a 3 percent discount rate), that 
compared to the total social costs of the rule (i.e., nearly $11 
billion) the rule cannot be justified were EPA properly to interpret 
CAA section 112(n)(1) and undertake the sort of regulatory analysis 
Congress intended. The commenter stated that the reason that the EPA 
touts in this rulemaking the health benefits EPA attributes to the 
reduction of non-hazardous air pollutants (again, primarily PM), the 
regulation of which is authorized under provisions of the CAA apart 
from CAA section 112, is to elide the inconvenient truth regarding the 
truly trivial nature of the benefits attributable to HAP regulation 
itself. The commenter concludes that the EPA distorts CAA section 
112(n)(1)(A) ``beyond all recognition.''
    One commenter stated that the EPA is directed by CAA section 
112(n)(1)(A) to study the ``hazards to public health anticipated to 
occur as a result of emissions'' by EGUs of ``pollutants listed under 
subsection (b) of this section''--i.e., HAP and HAP alone. Thereafter, 
the EPA is authorized to regulate EGU HAP emissions if, and only if, 
they determine that ``such regulation'' of HAP emissions is 
``appropriate and necessary'' to address the ``hazards to public 
health'' that may be attributable to HAP emissions. According to the 
commenter, by contrast, in this rulemaking, the EPA has seized upon the 
fact that the control of EGU HAP emissions will also control non-HAP 
(such as PM), and then seeks to justify the regulation of HAP emissions 
based almost entirely on the health benefits of the reductions in non-
HAP emissions that would be coincidentally achieved. The commenter 
believes that this ``regulatory sleight-of-hand'' runs afoul of 
congressional intent and is unlawful.
    Response: The commenter alleges that the health-related benefits to 
regulating HAP emissions from EGUs are ``questionable and miniscule,'' 
and that the only real benefits stem from non-HAP emissions, such as 
PM. The commenter also implies that regulation of HAP is nothing more 
than a straw man and that the Agency's ultimate goal is to regulate 
other pollutants, and specifically PM. These allegations are wholly 
without merit. The Agency has conducted comprehensive technical 
analyses that confirm that HAP emissions from EGUs pose a hazard to 
public health. The analyses are discussed at length elsewhere in this 
final rule, and a review of the proposed and final rules utterly 
refutes commenter's assertion that PM reductions form the basis for the 
appropriate and necessary finding. In addition, the commenter appears 
to ignore the Agency's findings concerning the hazards to public health 
and the environment posed by HAP emissions simply because the Agency is 
not able to quantify many of the benefits associated with reductions of 
HAP emissions from EGUs or because the estimated HAP benefits that are 
quantified are small in relation to the co-benefits achieved through 
reductions in non-HAP air pollutants, such as PM and SO2, 
which are surrogates for certain HAP. The Agency is regulating EGUs 
pursuant to section 112(d) for all of the reasons explained in the 
preamble and discussed elsewhere in this response to comments. The 
commenter fails to recognize that the statute neither requires a cost-
benefit analysis prior to finding it appropriate and necessary to 
regulate EGUs, nor requires such analysis prior to setting emission 
standards. Indeed, Congress expressly precluded consideration of costs 
when setting MACT floors. As explained below, the EPA does not believe 
that it is appropriate to consider costs when

[[Page 9324]]

determining whether to regulate EGUs under CAA section 112.
    Comment: One commenter stated that the EPA has ignored the language 
and intent of CAA section 112(n)(1)(A), as interpreted based on 
Representative Oxley's statements, and that the Agency's interpretation 
of this provision violates step one of Chevron. Under Chevron where the 
``intent of Congress is clear,'' that is the ``end of the matter,'' for 
both the implementing agency and a reviewing court ``must give effect 
to the unambiguously expressed intent of Congress.'' Chevron, 467 U.S. 
at 842-43. The commenter asserts that the legislative history of CAA 
section 112(n)(1)(A) ``sheds considerable light on Congress' unique 
approach to regulation of EGUs under CAA Sec.  112.'' According to the 
commenter, on April 3, 1990, the Senate passed S. 1630. The Senate bill 
would have required EPA to list EGUs under CAA section 112(c) and to 
regulate them under the MACT provisions of CAA section 112(d). See S. 
1630 section 301, 3 1990 Legis. Hist. at 4407. Thereafter, the House of 
Representatives passed a modified version of S. 1630 on May 23, 1990. 
This House version substantially changed the provisions of CAA section 
112 as they applied to EGUs. See 1 1990 Legis. Hist. at 572-73. The 
House version was virtually identical to the current CAA section 
112(n)(1)(A), and was ultimately adopted by the conference committee, 
enacted by Congress and signed into law. According to the commenter, 
Congress expressly rejected the ``list-under-(c)-and-regulate-under-
(d)'' approach that S. 1630 would have applied to EGUs, and that 
Congress did choose to apply to other source categories. The commenter 
stated that the EPA's interpretation that the Agency is ``required to 
establish emission standards for EGUs consistent with the requirements 
set forth in section 112(d)'' (Id. at 24,993/3) fails to take the 
legislative history into account, and in a footnote, the commenter 
states that the Agency erred by not addressing the legislative history 
as it did in the 2005 action.
    Response: For the reasons stated above, we believe commenter's 
reliance on the single statement of one legislator is flawed. In 
addition, in a footnote the commenter stated that the EPA recognized 
``that it had to address'' the legislative history in its 2005 action, 
and that the EPA erred in this case because we did not address the 
legislative history. The commenter cites no case law to support its 
contention that an Agency must ``address'' unpersuasive legislative 
history. Further, in the 2005 action, the EPA relegated to a footnote 
the Oxley statement that commenter relies on so heavily even though the 
statement supported the interpretation we provided in that rule. We 
recognized then what the commenter fails to recognize now, which is 
that the Agency cannot argue that the meaning of CAA section 
112(n)(1)(A) is clear based on the statements of one legislator.
    Furthermore, the Agency's interpretation does not violate Chevron 
Step 1. The terms ``appropriate'' and ``necessary'' are ambiguous. The 
statements of a lone legislator do not transform those ambiguous words 
into a Chevron Step 1 situation.
    Moreover, the commenter's assertion that Congress unambiguously 
defined the factors to consider in making the appropriate determination 
is without merit. We fully explain in the preamble to the proposed rule 
the basis for the Agency's interpretation, and we are not revising that 
interpretation based on the comments received.
    Finally, the EPA notes that the sentence concerning regulation 
under CAA section 112(d) that the commenter quotes from the preamble 
states, in full: ``Congress did not exempt EGUs from the other 
requirements of section 112 and, once listed, the EPA is required to 
establish emission standards for EGUs consistent with the requirements 
set forth in section 112(d), as described above.'' 76 FR 24993 
(emphasis added). The EPA discusses requirements to regulate section 
112(c) listed sources under section 112(d) in response to other 
comments.
c. Consideration of Both Environmental Effects and Health Effects From 
Other Sources
    Comment: Several commenters stated that the EPA acts contrary to 
congressional intent when the Agency considers itself ``thereby 
authorized to consider `environmental effects' and the effects of HAP 
emissions from non-EGU sources, in making its `appropriate and 
necessary' finding under subparagraph (n)(1)(A).''
    Commenters assert that the EPA misreads CAA section 112(n)(1)(B) 
and (C) to inject environmental effects in the CAA section 112(n)(1)(A) 
determination. According to one commenter the plain language of CAA 
section 112(n)(1) establishes that regulation of EGUs is to be 
predicated solely on ``hazards to public health'' attributable to HAP 
emissions. The legislative history providing that the EPA ``may 
regulate [EGUs] only if the studies described in section 112(n) clearly 
establish that emissions of any pollutant * * * from such units cause a 
significant risk of serious adverse risk to the public health'' 
confirms that plain language. See Oxley Statement at 1416-17. The 
commenter further stated that nothing on the face of CAA section 
112(n)(1)(A) indicates that Congress intended that the EPA should (or 
must) take into account any additional information that might be 
developed through the other studies mentioned in subparagraphs 
(n)(1)(B) and (C) (i.e., the Mercury Study \56\ and the NAS Study 
\57\), such as HAP emissions from non-EGU sources. The commenter also 
identified other provisions of section 112 that specifically require 
consideration of environmental effects and states that Congress would 
have requires such consideration in CAA section 112(n)(1) if it had 
wanted EPA to consider environmental effects.
---------------------------------------------------------------------------

    \56\ U.S. EPA. 1997. Mercury Study Report to Congress. EPA-452/
R-97-003. December.
    \57\ NAS, 2000.
---------------------------------------------------------------------------

    The commenter makes a related assertion that the EPA acts contrary 
to congressional intent by assuming authority to assess the ```hazard 
to public health or the environment [from] HAP emissions from EGUs 
alone' or the `result of HAP emissions from EGUs in conjunction with 
HAP emissions from other sources''' (citing 76 FR at 24,988/1). 
According to the commenter, the only evident basis for the Agency's 
interpretation that, in making its ``appropriate and necessary'' 
finding, the EPA can (and should) take into account HAP emissions from 
sources other than EGUs, is that the Mercury Study authorized by CAA 
112(n)(1)(B) references ``mercury emissions from * * * municipal waste 
combustion units, and other sources, including area sources,'' in 
addition to EGUs. The commenter asserts, however, that subparagraph 
(n)(1)(A) identifies the Utility Study as the sole study to inform 
EPA's ``appropriate and necessary'' finding. The commenter states that 
if Congress had intended that the EPA take into account information 
developed through the Mercury Study, Congress ``would not have 
specified that the EPA was to predicate its `appropriate and necessary' 
finding on the `results of the study required by this subparagraph' 
(n)(1)(A).''
    Commenter also cites to a number of other section 112 provisions 
that expressly address environmental effects and the commenter states 
the only conclusion to draw from the inclusion in those provisions and 
the absence of such language in section 112(n)(1)(A) is that Congress 
intended public health to be the only basis for the appropriate and 
necessary finding.

[[Page 9325]]

    Response: The commenter again relies in part on the statements of 
one legislator to attack EPA's reasoned interpretation of an ambiguous 
statute. To the extent the commenter's arguments rely on this limited 
evidence, we refer to the response above. As we stated above, CAA 
section 112(n)(1) is an ambiguous statutory provision; thus, the EPA's 
interpretation, not commenter's, is entitled to considerable deference 
if it is a reasonable reading of the statute. Chevron, 467 U.S. at 843-
44. For the reasons described herein and in the proposal, we believe 
that we have reasonably interpreted the statutory terms at issue here. 
The Agency directs attention to section III.A. of the proposed rule, 
which includes a thorough discussion of the Agency's interpretation of 
the relevant statutory terms. To the extent the commenters disagree 
with EPA's interpretations, the EPA refers back to its discussion in 
the proposal and responds to the comments as follows.
    The commenter appears to maintain that the EPA must interpret the 
scope of the appropriate and necessary finding solely in the context of 
the CAA section 112(n)(1)(A) Utility Study, such that only hazards to 
public health and only EGU HAP emissions may be considered. The 
commenter incorrectly conflates the requirements for the Utility Study 
with the requirement to regulate EGUs under CAA section 112 if EPA 
determines it is appropriate and necessary to do so. The commenter 
concedes that the Agency may consider information other than that 
contained in the Utility Study, but only to the extent it relates 
specifically to hazards to public health directly attributable to HAP 
emissions from EGUs. We agree that we may consider additional 
information other than that contained in the Utility Study, as we 
stated in the preamble to the proposed rule, because courts do not 
interpret phrases like ``after considering the results of'' in a manner 
that precludes the consideration of other information. See United 
States v. United Technologies Corp., 985 F.2d 1148, 1158 (2nd Cir. 
1993) (``based upon'' does not mean ``solely); \58\ see also 76 FR 
24988. We further explained in the preamble to the proposed rule that 
it was reasonable to interpret the scope of the appropriate and 
necessary finding in the context of all three studies required under 
CAA section 112(n)(1) because the provision is title ``Electric utility 
steam generating units.'' \59\ The commenter has provided little more 
than unpersuasive legislative history to support its restrictive 
interpretation of our authority. Id.
---------------------------------------------------------------------------

    \58\ Several commenters have taken issue with our citation to 
United States v. United Technologies Corp. because the language at 
issue in that case was ``based upon'' and the language of section 
112(n)(1)(A) is ``after considering the results of.'' We believe 
that, if anything, ``based upon'' is more prescriptive than ``after 
considering the results of'' such that the case supports the 
Agency's interpretation that additional information other than the 
Utility Study may be considered in making the appropriate and 
necessary finding.
    \59\ 76 FR 24986-87.
---------------------------------------------------------------------------

    The commenter also argues that the statute clearly prohibits the 
Agency from considering adverse environmental effects or the cumulative 
effects of HAP emissions from EGUs and other sources based on its claim 
that the statute is clear when one properly considers the legislative 
history. Again, the commenter has provided no support for its 
contention other than the statements of one Representative and the 
improper conflation of the CAA section 112(n)(1)(A) direction on the 
conduct of the Utility Study and the appropriate and necessary finding. 
Congress left it to the Agency to determine whether it is appropriate 
and necessary to regulate EGUs under CAA section 112 and the statute 
does not limit the Agency to considering only hazards to public health 
and only harms directly and solely attributable to EGUs.
    The commenter stated that Congress specifically told EPA when it 
wanted EPA to consider adverse environmental effects in CAA section 112 
and cites to several provisions of the Act that require consideration 
of adverse environmental effects. The commenter ignores CAA section 
112(n)(1)(B), which directs the Agency to consider adverse 
environmental effect. In any event, even were we to view section 
112(n)(1)(A) in isolation, as the commenter suggests, we still maintain 
that we can consider adverse environmental effects under 112(n)(1)(A). 
Nothing in section 112(n)(1)(A) precludes consideration of 
environmental effects. Congress required the Agency to assess whether 
it is appropriate and necessary to regulate EGUs under section 112. We 
believe that adverse environmental effects can be considered in the 
appropriate analysis. Congress specifically directed the Agency to 
consider adverse environmental effects when delisting source categories 
pursuant to section 112(c)(9), and thus we believe it is reasonable to 
consider such effects when determining whether it is appropriate to 
regulate such units under section 112, especially given that Congress 
did not limit our appropriate and necessary inquiry to the Utility 
Study. See CAA section 112(c)(9)(B)(ii).
    Moreover, the other provisions of CAA section 112 that specifically 
discuss environmental effects have purposes that are distinguishable 
from CAA section 112(n)(1), and we do not believe one can reasonably 
draw the conclusion that the commenter does when comparing those 
provisions to CAA section 112(n)(1)(A). The lack of a requirement to 
consider environmental effects in CAA section 112(n)(1)(A) does not 
equate to a prohibition on the consideration of environmental effects 
as the commenter concludes. The EPA maintains that it reasonably 
concluded that we should protect against identified or potential 
adverse environmental effects absent clear direction to the contrary.
    Concerning the consideration of the cumulative effect of HAP 
emissions from EGUs and other sources, we provided a reasonable 
interpretation of the statute and noted that our interpretation, unlike 
commenters, does not ``ignore the manner in which public health and the 
environment are affected by air pollution. An individual that suffers 
adverse health effects as the result of the combined HAP emissions from 
EGUs and other sources is harmed, irrespective of whether HAP emissions 
from EGUs alone would cause the harm.'' \60\
---------------------------------------------------------------------------

    \60\ 76 FR 24988.
---------------------------------------------------------------------------

d. Finding for All HAP To Be Regulated
    Comment: Several commenters stated that for those EGU HAP for which 
the Agency makes no CAA section 112(n)(1)(A) determination, their 
regulation under CAA section 112 is not authorized. For example, one 
commenter maintains that the Agency could regulate HAP emissions from 
EGUs under CAA section 112(n). Accordingly, to the extent that the EPA 
reads CAA section 112, as construed by National Lime Ass'n, as 
compelling it to regulate all HAP emitted by EGUs, should the Agency 
make an ``appropriate and necessary'' determination under CAA section 
112(n)(1)(A) with respect to a single HAP (e.g., Hg), the EPA stands 
poised to commit a fundamental legal error that will condemn the final 
rule on review. Cf., e.g., PDK Laboratories, Inc., 362 F.3d at 797-98; 
Holland v. Nat'l Mining Ass'n, 309 F.3d at 817 (where an agency applies 
a Court of Appeals ``interpretation * * * because it believed that it 
had no choice'' and that it ``was effectively `coerced' to do so,'' 
then the agency ``cannot be deemed to have exercised its reasoned 
judgment'').
    Response: We do not agree with the commenter's assertion that 
Congress intended EPA to regulate only those EGU HAP emissions for 
which an appropriate and necessary finding is

[[Page 9326]]

made, and the commenter has cited no provision of the statute that 
states a contrary position. The EPA reasonably concluded that we must 
find it ``appropriate'' to regulate EGUs under CAA section 112 if we 
determine that a single HAP emitted from EGUs poses a hazard to public 
health or the environment. If we also find that regulation is 
necessary, the Agency is authorized to list EGUs pursuant to CAA 
section 112(c) because listing is the logical first step in regulating 
source categories that satisfy the statutory criteria for listing under 
the statutory framework of CAA section 112. See New Jersey, 517 F.3d at 
582 (stating that ``[s]ection 112(n)(1) governs how the Administrator 
decides whether to list EGUs. * * *''). As we noted in the preamble to 
the proposed rule, D.C. Circuit precedent requires the Agency to 
regulate all HAP from major sources of HAP emissions once a source 
category is added to the list of categories under CAA section 112(c). 
National Lime Ass'n v. EPA, 233 F.3d 625, 633 (D.C. Cir. 2000). 76 FR 
24989.
    The commenter does not explain its issues with our interpretation 
of how regulation under section 112 works--i.e. making a determination 
that a source category should be listed under CAA section 112(c), 
listing the source category under CAA section 112(c), regulating the 
source category under CAA section 112(d), and conducting the residual 
risk review for sources subject to MACT standards pursuant to CAA 
section 112(f). Instead, it asserts that our decision is flawed because 
the interpretation we provided does not account for all the 
alternatives for regulating EGUs under section 112, and that we have 
not properly exercised our discretion leading to a fatal flaw in our 
rulemaking.
    The commenter also ignores the language of section 112(n)(1)(A). As 
explained in the proposed rule, the use of the terms section, 
subsection, and subparagraph in section 112(n)(1)(A) demonstrates that 
Congress was consciously distinguishing the various provisions of 
section 112 in directing EPA's action under section 112(n)(1)(A). 
Congress directed the Agency to regulate utilities ``under this 
section,'' not ``under this subparagraph,'' and accordingly EGUs should 
be regulated under section 112 in the same manner as other categories 
for which the statute requires regulation. Furthermore, the D.C. 
Circuit Court found that section 112(n)(1) ``governs how the 
Administrator decides whether to list EGUs'' and that once listed, EGUs 
are subject to the requirements of section 112. New Jersey, 517 F.3d at 
583. Indeed, the D.C. Circuit Court expressly noted that ``where 
Congress wished to exempt EGUs from specific requirements of section 
112, it said so explicitly,'' noting that ``section 112(c)(6) expressly 
exempts EGUs from the strict deadlines imposed on other sources of 
certain pollutants.'' Id. Congress did not exempt EGUs from the other 
requirements of section 112, and once listed, the EPA is reasonably 
regulating EGUs pursuant to the standard-setting provisions in section 
112(d), as it does for all other listed source categories.
    The commenter provided no alternative theory for regulating EGUs 
under CAA section 112, other than to state that the EPA could regulate 
under CAA section 112(n)(1). However, even assuming for the sake of 
argument, that we could issue standards pursuant to CAA section 
112(n)(1), we would decline to do because there is nothing in section 
112(n)(1)(A) that provides any guidance as to how such standards should 
be developed. Any mechanism we devised, absent explicit statutory 
support, would likely receive less deference than a CAA section 112(d) 
standard issued in the same manner in which the Agency issues standards 
for other listed source categories. We would also decline to establish 
standards under section 112(n)(1) because Congress did provide a 
mechanism under CAA sections 112(d) and (f) for establishing emission 
standards for HAP emissions from stationary sources and it is 
reasonable to use that mechanism to regulate HAP emissions from EGUs.
e. Considering Costs in Finding
    Comment: Several commenters assert that the EPA must consider costs 
in assessing whether regulation of EGUs is appropriate under CAA 
section 112(n)(1)(A). Commenters posit that the EPA's position that 
``the term `appropriate' * * * does not allow for the consideration of 
costs in assessing whether hazards * * * are reasonably anticipated to 
occur based on EGU emissions,'' 76 FR at 24,989/1, does not withstand 
scrutiny. According to the commenters, the treatment of ``costs'' under 
section 112(c) does not support the Agency's position, and the process 
by which sources may be ``delisted'' under section 112(c)(9), including 
no consideration of costs, sheds no light on the circumstances under 
which it may be ``appropriate'' to regulate EGUs under section 
112(n)(1)(A).
    Commenters characterize as ``unintelligible'' the EPA's position 
that it is ``reasonable to conclude that costs may not be considered in 
determining whether to regulate EGUs'' when ``hazards to public health 
and the environmental are at issue (citing 76 FR at 24989). ``Two 
commenters stated that a natural reading of the term ``appropriate'' 
would include the consideration of costs. According to the commenters, 
something may be found to be ``appropriate'' where it is ``specially 
suitable,'' ``fit,'' or ``proper.'' See Webster's Third New 
International Dictionary at 106 (1993). The term ``appropriate'' 
carries with it the connotation of something that is ``suitable or 
proper in the circumstances.'' See New Oxford American Dictionary (2d 
Ed. 2005). Considering the costs associated with undertaking a 
particular action is inextricably linked with any determination as to 
whether that action is ``specially suitable'' or ``proper in the 
circumstances.'' One commenter notes that in 2005 (70 FR 15994, 16000; 
March 29, 2005) the EPA used the dictionary definition of 
``appropriate,'' as being ``especially suitable or compatible'' and 
that it would be difficult to fathom how a regulatory program could be 
either ``suitable'' or ``compatible'' for a given public health 
objective without consideration of cost.
    One commenter asserts that on the face of CAA section 112(n)(1)(A), 
it is clear that the EPA is expected to consider costs. According to 
the commenter, that Congress intended that the EPA investigate and 
consider ``alternative control strategies'' for emissions as part of 
the section 112 (n)(1) Utility Study when making the ``appropriate and 
necessary'' determination refutes the notion that the Agency can, and 
indeed must, disregard the cost of regulation in making that 
determination, because the cost of a given emission ``control 
strategy'' is a central factor in any evaluation of ``alternative'' 
controls.
    Further, according to commenters, it is well-settled that CAA 
regulatory provisions should be read with a presumption in favor of 
considering costs (citing Michigan v. EPA, 213 F.3d 663, 678 (D.C. Cir. 
2000)), and the legislative history of section 112(n)(1)(A) confirms 
that Congress intended EPA to consider costs (citing Oxley Statement at 
1417).
    Commenters also assert that the EPA falsely represents that it 
``did not consider costs when making the ``appropriate'' determination 
in the EPA's December 2000 notice (76 FR at 24,989/2).
    Response: The commenters first take issue with EPA's explanation of 
why the Agency determined that costs should not be considered in making 
the appropriate determination. What

[[Page 9327]]

commenters do not identify is an express statutory requirement that the 
Agency consider costs in making the appropriate determination. Congress 
treated the regulation of HAP emissions differently in the 1990 CAA 
amendments because the Agency was not acting quickly enough to address 
these air pollutants with the potential to adversely affect human 
health and the environment. See New Jersey, 517 F.3d at 578. 
Specifically, following the 1990 CAA amendments, the CAA required the 
Agency to list source categories and nothing in the statute required us 
to consider costs in those listing decision, and we have not done so 
when listing other source categories. Thus, it is reasonable to make 
the listing decision, including the appropriate determination, without 
considering costs.
    The commenters next argue that the Agency is compelled by the 
statute to consider costs based on a dictionary definition of 
``appropriate'' and the CAA section 112(n)(1)(A) direction to consider 
alternative control strategies for regulating HAP emissions in the 
Utility Study.
    Concerning the definition of ``appropriate'', commenters stated:

    Not only is it ``reasonable'' for EPA to consider costs in 
determining whether it is ``appropriate'' to regulate EGU HAP 
emissions, a natural reading of the term indicates that excluding 
the consideration of costs would be entirely unreasonable. Something 
may be found to be ``appropriate'' where it is ``specially 
suitable,'' ``fit,'' or ``proper.'' See Webster's Third New 
International Dictionary at 106 (1993). The term ``appropriate'' 
carries with it the connotation of something that is ``suitable or 
proper in the circumstances.'' See New Oxford American Dictionary 
(2d Ed. 2005) at 76. Considering the costs associated with 
undertaking a particular action is inextricably linked with any 
determination as to whether that action is ``specially suitable'' or 
``proper in the circumstances.''

    The EPA believes the definition of ``appropriate'' that the 
commenters provide wholly support its interpretation and nothing about 
the definition compels a consideration of costs. It is appropriate to 
regulate EGUs under CAA section 112 because EPA has determined that HAP 
emissions from EGUs pose hazards to public health and the environment, 
and section 112 is ``specially suitable'' for regulating HAP emissions, 
and Congress specifically designated CAA section 112 as the ``proper'' 
authority for regulating HAP emissions from stationary sources, 
including EGUs. Section 112 of the CAA is ``suitable [and] proper in 
the circumstances'' because EPA has identified a hazard to public 
health and the environment from HAP emissions from EGUs and Congress 
directed the Agency to regulate HAP emissions from EGUs under that 
provision if we make such a finding. Cost does not have to be read into 
the definition of ``appropriate'' as commenter suggests. In addition, 
as stated elsewhere in response to comments, the Agency does not 
consider costs in any listing or delisting determinations, and the EPA 
maintains that it is reasonable to assess whether to list EGUs (i.e. 
the appropriate and necessary finding) without considering costs.
    The commenters' argument that costs must be considered based on the 
CAA section 112(n)(1)(A) requirement to ``develop and describe 
alternative control strategies'' in the Utility Study is equally 
flawed. The argument is flawed because Congress did not direct the 
Agency to consider in the Utility Study the costs of the controls when 
evaluating the alternative control strategies. In addition, the EPA did 
not consider the costs of the alternative controls in the Utility 
Study, as implied by the commenter. Thus, even viewing section 
112(n)(1)(A) in isolation, there is nothing in that section that 
compels EPA to consider costs. For the reasons described herein, we do 
not believe that it is appropriate to consider costs in determining 
whether to regulate EGUs under section 112.
    Additionally, one commenter attempts to refute EPA's statement in 
the preamble to the proposed rule that the EPA did not consider costs 
in the 2000 finding by pointing to the only two mentions of cost in 
that notice. However, the EPA did not say that costs were not mentioned 
in the 2000 finding and a review of the regulatory finding will show 
that costs were not considered in the regulatory finding. 65 FR 79830 
(December 20, 2000) (``Section III. What is EPA's Regulatory 
Finding?'').
f. Considering Requirements of the CAA in ``Necessary''
    Comment: Several commenters disagree with EPA's position that it 
need consider ``only those requirements that Congress directly imposed 
on EGUs through the CAA as amended in 1990,'' for which ``EPA could 
reasonably predict HAP emission reductions at the time of the Utility 
Study.'' According to the commenters, the statutory language of CAA 
section 112(n)(1) requires that the EPA consider the scope and effect 
of EGU HAP emissions after the imposition of all of the 
``requirements'' of the CAA, not just the Acid Rain program. The 
commenter maintains that it would have been easy enough for Congress in 
subparagraph 112(n)(1)(A) to specify ``after imposition of the 
requirements of Title IV of this chapter,'' but Congress did not. The 
commenters further add that the legislative history confirms that 
Congress meant something much broader than that, providing that the EPA 
is authorized to regulate EGUs under CAA section 112 only after 
``taking into account compliance with all provisions of the act and any 
other Federal, State, or local regulation and voluntary emission 
reductions.'' The commenters stated that the CAA's ``requirements'' 
include the submission by states of ozone and fine PM attainment 
demonstrations, as well as SIP provisions needed to reach attainment of 
the NAAQS because such provisions could include controls on EGUs to 
reduce SO2 and NOX, which controls could also 
result in a reduction in Hg emissions.
    Response: The commenter's characterization of the facts is flawed 
and its reliance on legislative history that is in direct conflict with 
the express terms of the statute is unpersuasive.
    On the facts, the EPA explained in the preamble to the proposed 
rule its interpretation of the phrase ``after imposition of the 
requirements of [the Act]'' as it related to the conduct of the Utility 
Study.\61\ We reasonably concluded that, since Congress only provided 3 
years after enactment to conduct the study, the phrase referred to 
requirements that were directly imposed on EGUs through the CAA 
amendments and for which the Agency could reasonably predict co-benefit 
HAP emission reductions. Id. The EPA did not state that the phrase only 
applied to the Acid Rain program, as commenter asserts, and the Utility 
Study in fact discussed other regulations, including the NSPS for EGUs 
and revised NAAQS. With regard to the latter, the EPA ultimately 
determined that it could not sufficiently quantify the reductions that 
might be attributable to the NAAQS because states are tasked with 
implementing those standards. See Utility Study, pages ES-25, 1-3, 2-
32. Conversely, commenter's position is that the EPA must consider 
implementation of all the requirements of the CAA, but it does not 
indicate how in conducting the Utility Study the Agency could have 
possibly considered co-benefit HAP reductions attributable to all 
future CAA requirements. The Agency appropriately considered the other 
requirements of the Act in the Utility Study and considered those 
requirements in determining that it was

[[Page 9328]]

necessary to regulate coal- and oil-fired EGUs in December 2000.
---------------------------------------------------------------------------

    \61\ 76 FR 24990.
---------------------------------------------------------------------------

    Although not required, the Agency in the preamble to the proposed 
rule conducted further analyses in support of the 2000 finding. In 
doing so, we considered a number of requirements that far exceed what 
Congress contemplated when enacting CAA section 112(n)(1)(A)), and our 
analyses still show that it remains necessary to regulate coal- and 
oil-fired EGUs under section 112. 76 FR 24991.
    We maintain that we have reasonably interpreted the requirement to 
consider the hazards to public health and the environment reasonably 
anticipated to occur after imposition of the requirements of the Act as 
explained in the preamble to the proposed rule.\62\ In addition, as 
stated above, we also believe it would be reasonable to find it 
necessary to regulate HAP emissions from EGUs based on our finding that 
such emissions pose a hazard to public health and the environment today 
without considering future reductions that we currently project to 
occur as the result of imposition of CAA requirements that are not yet 
effective (e.g., CSAPR).
---------------------------------------------------------------------------

    \62\ 76 FR 24990.
---------------------------------------------------------------------------

    Moreover, Representative Oxley's statement cited by the commenter 
is not consistent with the express terms of CAA section 112(n)(1)(A) on 
this issue. Representative Oxley stated that the EPA was to take ``into 
account compliance with all the provisions of the act and any other 
Federal, State, or local regulation and voluntary emission 
reductions,'' but CAA section 112(n)(1)(A) directs the Agency to 
consider ``imposition of the requirements of this chapter,'' which 
means the CAA. The Agency reasonably focused on the requirements of the 
Clean Air Act, which are federally enforceable, and declined to include 
potential future reductions that may be attributable to voluntary 
emission reduction programs or state and local regulations that have no 
basis in the Clean Air Act and are not federally enforceable. In 
addition to the statutory direction not to consider such requirements, 
the EPA believes it is reasonable not to include potential reductions 
attributable to such requirements because the Agency cannot assure that 
such requirements and the attendant HAP reductions will remain absent 
regulation under section 112. Finally, the commenter implies that EPA's 
position is that the Agency will only consider requirements of the Act 
that directly regulate HAP emissions. The EPA never stated or suggested 
that interpretation and a fair reading of the proposed rule will 
demonstrate that EPA considered requirements that achieve co-benefit 
HAP emission reductions, for example the Transport Rule (known as 
CSAPR).
    Comment: One commenter stated that, under CAA section 112, 
regulating EGUs is permissible only insofar as it is focused, targeted, 
and predicated on concrete findings by the Agency that such regulation 
is indeed ``necessary.'' According to the commenter, the EPA construes 
CAA section 112(n)(1)(A) as permitting it to find that it is 
``necessary'' to regulate EGUs even where the Agency does not actually 
know whether it is ``necessary'' to regulate EGUs. Citing the D.C. 
Circuit, the EPA suggests that ```there are many situations in which 
the use of the word `necessary,' in context, means something that is 
done, regardless of whether it is indispensible,''' in order to 
```achieve a particular end.''' 76 FR 24990, quoting Cellular 
Telecommunications v. FCC, 330 F.3d 502, 510 (D.C. Cir. 2003). The 
commenter stated that in the ``context'' of CAA section 112(n)(1)(A), 
as informed by the relevant legislative history from Representative 
Oxley, it is clear that regulation of EGU HAP emissions can be 
considered ``necessary'' only if EPA were to ``clearly establish'' that 
such regulation was effectively ``indispensible'' to address the 
identified harm. As EPA concedes that it has made no such determination 
here, its proposal is fatally flawed for that reason alone.
    The commenter further asserts that the EPA erred when it concluded 
that it may `` `determine it is necessary to regulate under section 
112' when the Agency is `uncertain whether imposition of the 
requirements of the CAA will address the identified hazards''' (citing 
76 FR at 24,991/3). According to the commenter, the EPA ``cannot take 
refuge in its own `uncertainty' to support a finding that it is 
`necessary' to regulate EGUs under section 112, and the Act precludes 
the EPA from ```err[ing] on the side of regulation''' in face of 
uncertainty (id.). The commenter also implies that the finding was 
based on non-HAP emissions.
    Response: The commenter again relies on the legislative statements 
of one Representative and asserts that the statements are controlling. 
The EPA disagrees with commenter and maintains that its interpretation 
of the term ``necessary'' is reasonable. 76 FR 24990-92 (Section 
III.A.2.b of the preamble to the proposed rule contains the EPA's 
interpretation of the term ``necessary''.) 76 FR 24990-92 (Section 
III.A.2.b of the proposed rule contains EPA's interpretation of the 
term ``necessary''.) The commenter also, in a footnote, implies that 
EPA based the appropriate and necessary finding on non-HAP air 
pollution. The commenter is wrong as explained in more detail above.
    As an initial matter, this comment is only addressing one aspect of 
the Agency's interpretation of the term necessary. As EPA stated at 
proposal:

    If we determine that the imposition of the requirements of the 
CAA will not address the identified hazards, EPA must find it 
necessary to regulate EGUs under section 112. Section 112 is the 
authority Congress provided to address hazards to public health and 
the environment posed by HAP emissions and section 112(n)(1)(A) 
requires the Agency to regulate under section 112 if we find 
regulation is ``appropriate and necessary.'' If we conclude that HAP 
emissions from EGUs pose a hazard today, such that it is 
appropriate, and we further conclude based on our scientific and 
technical expertise that the identified hazards will not be resolved 
through imposition of the requirements of the CAA, we believe there 
is no justification in the statute to conclude that it is not 
necessary to regulate EGUs under section 112.

76 FR 24991.

    The EPA has determined that the imposition of the requirements of 
the CAA will not address the hazards to public health or hazards to the 
environment that EPA has identified; therefore, it is necessary to 
regulate EGUs under CAA section 112.
    The EPA further interpreted the statute to allow the Agency to find 
that it is necessary to regulate EGUs under other circumstances, and it 
is with one of our additional interpretations that commenter takes 
issue. Specifically, the commenter argues that EPA's interpretation 
authorizes the Agency to find it necessary to regulate EGUs when we are 
uncertain it is necessary, but that misconstrues our interpretation and 
the record. At proposal, the EPA stated:

    In addition, we may determine it is necessary to regulate under 
section 112 even if we are uncertain whether the imposition of the 
requirements of the CAA will address the identified hazards. 
Congress left it to EPA to determine whether regulation of EGUs 
under section 112 is necessary. We believe it is reasonable to err 
on the side of regulation of such highly toxic pollutants in the 
face of uncertainty. Further, if we are unsure whether the other 
requirements of the CAA will address an identified hazard, it is 
reasonable to exercise our discretion in a manner that assures 
adequate protection of public health and the environment. Moreover, 
we must be particularly mindful of CAA regulations we include in our 
modeled estimates of future emissions if they are not

[[Page 9329]]

final or are still subject to judicial review ([e.g.], the Transport 
Rule). If such rules are either not finalized or upheld by the 
Courts, the level of risk would potentially increase.

Id.
    The CAA requires EPA to exercise its discretion in determining 
whether regulation under section 112 is necessary, and the D.C. Circuit 
has stated that ``there are many situations in which the use of the 
word `necessary,' in context, means something that is done, regardless 
of whether it is indispensible, to achieve a particular end.'' See 
Cellular Telecommunications & Internet Association, et al. v. FCC, 330 
F.3d 502, 510 (D.C. Cir. 2003). The EPA's interpretation of 
``necessary'' is reasonable in the context of CAA section 112(n)(1)(A).
    The commenter stated that EPA concedes that the Agency has not 
``clearly established'' that regulation of HAP emissions under CAA 
section 112 is ``indispensible.'' The EPA has conceded nothing but, 
more importantly, the supposed standard that the commenter presents for 
evaluating whether it is necessary to regulate HAP emissions from EGUs 
is not required by the statute. Even the limited legislative history on 
which the commenter incorrectly relies does not espouse such a 
standard. The commenter specifically takes issue with EPA's statement 
that the Agency may find it is necessary to regulate EGUs under CAA 
section 112 if we are ``uncertain whether imposition of the other 
requirements of the CAA will sufficiently address the identified 
hazards.'' 76 FR at 24990. The commenter has again misinterpreted the 
Agency's position by stating that ``EPA construes CAA section 
112(n)(1)(A) as permitting it to find that it is ``necessary'' to 
regulate EGUs even where the Agency does not actually know whether it 
is ``necessary'' to regulate EGUs.'' Instead, the EPA maintains that it 
may be necessary to regulate EGUs under CAA section 112 if we identify 
a hazard to public health or the environment that is appropriate to 
regulate today and our projections into the future do not clearly 
establish that the imposition of the requirements of the CAA will 
address the identified hazard in the future. Making a prediction about 
future emission reductions from a source category is difficult for 
statutory provisions that do not mandate direct control of the given 
source category or pollutants of concern. We maintain that erring on 
the side of caution is appropriate when the protection of public health 
and the environment from HAP emissions is not assured based on our 
modeling of future emissions.
    Furthermore, as we stated in the preamble to the proposed rule, we 
believe it would be reasonable to find it appropriate and necessary to 
regulate EGUs under section 112 today based on a determination that HAP 
emissions from EGUs pose a hazard to public health and the environment 
without considering future HAP emission reductions. 76 FR 24991, n.14. 
We maintain this is reasonable because ``Congress could not have 
contemplated in 1990 that EPA would have failed in 2011 to have 
regulated HAP emissions from EGU's where hazards to public health and 
the environment remain.'' Id. The phrase ``after imposition of the 
requirements of [the Act]'' as contemplated CAA section 112(n)(1)(A) 
could be read to apply only to those requirements clearly and directly 
applicable to EGUs under the 1990 CAA amendments, all of which have 
been implemented and still hazards to public health and the environment 
from HAP emissions from EGUs remain.
g. Listing EGUs Under 112
    Comment: One commenter stated that even if EPA were to establish 
under CAA section 112(n)(1)(A) that it is ``appropriate and necessary'' 
to regulate HAP emissions from EGUs, regulating those emissions in the 
form of a MACT standard established pursuant to CAA section 112(d) is 
contrary to the plain language of the Act. According to the commenter, 
if EPA proceeds to finalize the proposal and adopts such a standard, 
the rule will for this reason alone be ``dead-on-arrival''. According 
to the commenter, the EPA apparently believes that its only option in 
regulating EGU HAP emissions is establishing a MACT standard under CAA 
section 112(d). In the preamble to its proposal, the commenter states 
that EPA contends that, ``once the appropriate and necessary finding is 
made,'' EGUs are then ``subject to section 112 in the same manner as 
other sources of HAP emissions''--i.e., by ``listing'' EGUs under CAA 
section 112(c) and adopting a MACT standard under CAA section 112(d). 
See 76 FR 24993/2 (emphasis added). The commenter further stated that, 
given that Congress ``directed the Agency to regulate utilities `under 
this section' [i.e., CAA section 112],'' EPA continues, it follows that 
``EGUs should be regulated in the same manner as other categories for 
which the statute requires regulation.'' Id. (emphasis added). The 
commenter asserts that as EPA sees it, because ``Congress did not 
exempt EGUs from the other requirements of section 112,'' once EGUs 
were ``listed'' under CAA section 112(c), the Agency was ``required to 
establish emission standards for EGUs consistent with the requirements 
set forth in section 112(d).'' Id. at 24,993/3 (emphasis added).
    The commenter stated that, in support of this reading of the CAA, 
the EPA invokes the decision of the U.S. Court of Appeals for the D.C. 
Circuit in New Jersey v. EPA, 517 F.3d 574 (D.C. Cir. 2008). The 
commenter further alleged that, according to EPA, the D.C. Circuit has 
``already held that section 112(n)(1) `governs how the Administrator 
decides whether to list EGUs.' '' See 76 FR 24993/2-3, quoting 517 F.3d 
at 583. The commenter stated that EPA construes that holding as 
indicating that, ``once listed, EGUs are subject to the requirements of 
section 112''--including, the EPA presumes, CAA section 112(d). Id. The 
commenter stated that elsewhere, the EPA construes CAA section 
112(n)(1) (A) as ``govern[ing] how the Administrator decides whether to 
list EGUs for regulation under section 112,'' and quotes the D.C. 
Circuit's observation in New Jersey that ``Section 112(n)(1) governs 
how the Administrator decides whether to list EGUs; it says nothing 
about delisting EGUs.'' See 76 FR 24981/2, quoting 517 F.2d at 582.
    The commenter asserts that EPA misinterprets the ``under this 
section'' language of CAA section 112(n)(1); overstates the 
significance of the New Jersey decision; and, as a consequence, 
misapprehends the scope of its own discretion to formulate regulatory 
standards for EGUs under CAA section 112. In light of these errors, the 
commenter maintains that EPA should withdraw the proposed MACT rule.
    One commenter stated that if Congress had intended that EPA 
regulate EGU HAP emissions only through a MACT standard, Congress could 
have--and presumably would have--directed the Agency to regulate EGU 
emissions ``under CAA section 112(d).'' Thus, the commenter maintained 
that EPA's authority to regulate EGU HAP emissions is not derived from 
any particular subsection of CAA section 112. Rather, the commenter 
stated that EPA is authorized to regulate ``under this section''--i.e., 
CAA section 112 generally--as may be ``appropriate and necessary.'' The 
commenter stated that there is nothing on the face of CAA section 
112(n)(1)(A) that specifies that regulation of EGUs must occur under 
CAA section 112(d). To the contrary, according to the commenter, a 
plain reading of CAA section 112(n)(1)(A), as interpreted based on the 
Oxley statement, indicates that establishing a

[[Page 9330]]

MACT standard for EGUs under CAA section 112(d) is not what Congress 
had in mind at all.
    Response: We do not agree with the commenter. The EPA interpreted 
CAA section 112(n)(1)(A) in a manner that gives meaning to all the 
words used in the provision. See NRDC v. EPA, 489 F.3d 1364, 1373 (D.C. 
Cir. 2007) (admonishing EPA for an interpretation of CAA section 
112(c)(9) that ignored certain words and the context in which they were 
used. The Court stated that ``EPA's interpretation would make the words 
redundant and one of them `mere surplusage,' which is inconsistent with 
a court's duty to give meaning to each word used by Congress.'') 
(citing TRW Inc. v. Andrews, 534 U.S. 19, 31, 122 S. Ct. 441, 151 L. 
Ed. 2d 339 (2001)). Specifically, in the preamble to the proposed rule, 
we stated:

    The statute directs the Agency to regulate EGUs under section 
112 if the Agency finds such regulation is appropriate and 
necessary. Once the appropriate and necessary finding is made, EGUs 
are subject to section 112 in the same manner as other sources of 
HAP emissions. Section 112(n)(1)(A) provision provides, in part, 
that: `[t]he Administrator shall perform a study of the hazards to 
public health reasonably anticipated to occur as a result of 
emissions by electric utility steam generating units of pollutants 
listed under subsection (b) of this section after imposition of the 
requirements of this chapter. * * * The Administrator shall regulate 
electric utility steam generating units under this section, if the 
Administrator finds such regulation is appropriate and necessary 
after considering the results of the study required by this 
subparagraph.'' Emphasis added.

    In the first sentence, Congress described the study and directed 
the Agency to evaluate the hazards to public health posed by HAP 
emissions listed under subsection (b) (i.e., CAA section 112(b)). The 
last sentence requires the Agency to regulate under this section (i.e., 
CAA section 112) if the Agency finds such regulation is appropriate and 
necessary after considering the results of the study required by this 
subparagraph (i.e., CAA section 112(n)(1)(A)). The use of the terms 
``section'', ``subsection'', and ``subparagraph'' demonstrates that 
Congress was consciously distinguishing the various provisions of CAA 
section 112 in directing the conduct of the study and the manner in 
which the Agency must regulate EGUs if the Agency finds it appropriate 
and necessary to do so. Congress directed the Agency to regulate 
utilities ``under this section,'' and accordingly EGUs should be 
regulated in the same manner as other categories for which the statute 
requires regulation. See 76 FR 24993.
    We maintain that our interpretation of the statute gives meaning to 
all the words, and the commenter's interpretation does not give any 
particular meaning to the requirement to ``regulate under this section 
[112]''. The commenter is correct that Congress could have in CAA 
section 112(n)(1)(A) directed EPA to regulate HAP from EGUs under CAA 
section 112(d) after making the appropriate and necessary finding, but 
the commenter presumes too much when it stated that Congress would have 
directed the Agency to regulate HAP emissions from EGUs in such a 
manner if that is what Congress wanted, simply by including the phrase 
``regulate under this paragraph'' or ``regulate under this 
subparagraph'' instead of directing the Agency to ``regulate under this 
section''. It did not do so.
    As we explained in the section II.A. of the proposed rule, CAA 
section 112 establishes a mechanism to list and regulate stationary 
sources of HAP emissions. 76 FR 24980-81. Regulation under CAA section 
112 generally requires listing under CAA section 112(c), regulation 
under CAA section 112(d), and, for sources subjected to MACT standards, 
residual risk regulations under CAA section 112(f) (as necessary to 
protect human health and the environment with an ample margin of 
safety). A determination that EGUs should be listed once the 
prerequisite appropriate and necessary finding is made is wholly 
consistent with the language of section 112(n)(1)(A), and listed 
sources must be regulated under CAA section 112(d). See CAA section 
112(c)(2); see also New Jersey, 517 F.3d at 583 (112(n)(1)(A) ``governs 
how the Administrator decides whether to list EGUs'').
    As noted above, Congress used the terms section, subsection, and 
subparagraph in section 112(n)(1)(A). The use of these three terms 
demonstrates that Congress was consciously distinguishing between the 
various provisions of section 112. Congress directed the Agency to 
regulate utilities ``under this section,'' and accordingly EGUs should 
be regulated in the same manner as other categories for which the 
statute requires regulation.
    Furthermore, the flaws in the commenter's interpretation are 
highlighted by other CAA section 112 provisions wherein Congress 
provided specific direction as to the manner of regulation. For 
example, CAA section 112(m)(6) requires the Administrator to determine 
``whether the other provisions of this section [112] are adequate'' and 
also indicates that ``[a]ny requirements promulgated pursuant to this 
paragraph * * * shall only apply to the coastal waters of the States 
which are subject to [section 328 of the CAA].'' (emphasis added).
    In addition, CAA section 112(n)(3) provides that when the Agency is 
``promulgating any standard under this section [112] applicable to 
publicly owned treatment works, the Administrator may provide for 
control measures that include pretreatment of discharges causing 
emissions of hazardous air pollutants and process or product 
substitutions or limitations that may be effective in reducing such 
emissions.'' Finally, CAA section 112(n)(5) directs the Agency to 
assess hydrogen sulfide emissions from oil and gas extraction and 
``develop and implement a control strategy for emissions of hydrogen 
sulfide to protect human health and the environment * * * using 
authorities under [the CAA] including [section 111] of this title and 
this section [112].'' (emphasis added). We believe these provisions 
provide ample evidence that Congress knew how to alter or caveat 
regulation under CAA section 112 when that was its intent. For these 
reasons, we believe commenter's argument is without merit.
    Comment: Two commenters stated that CAA section 112(n)(1)(A) does 
not specify that regulation of EGUs must proceed under CAA section 
112(d). According to the commenter, an argument could be made, 
therefore, that the CAA accords EPA with the discretion to regulate 
EGUs using strategies other than emission standards in CAA section 
112(d). The commenters also state that section 112(n)(1)(A) of the CAA 
requires that EPA ``develop and describe'' alternative control 
strategies for emissions which may warrant regulation under CAA section 
112. According to the commenters if Congress meant for EPA to have one 
sole regulatory option, i.e., regulation of EGUs only under CAA section 
112(d), then the development of alternative control strategies would be 
rendered meaningless because under CAA section 112(d)(3), the EPA is 
required to determine the level of control that is achieved by the best 
performing existing units for which it has data and then to impose that 
level of control on all existing units. The commenter further states 
that the development of ``alternative control strategies'' has no role 
to play in this process. One commenter does note that the consideration 
of ``alternative'' controls becomes relevant, if at all, only in those 
circumstances where EPA might seek to establish a ``Beyond-the-Floor'' 
MACT standard pursuant to CAA section 112(d)(2).

[[Page 9331]]

    Response: The commenters are correct that CAA section 112(n)(1)(A) 
directed the Agency to develop and describe in the Utility Study report 
to Congress alternative control strategies for HAP emissions from EGUs 
that may warrant regulation in the Utility Study, but the commenters' 
interpretation of and conclusion based on that language are both 
factually and legally inaccurate.
    The commenters appear to interpret the word ``alternative control 
strategies'' to mean something other than the traditional control 
technologies and control measures that are used to control HAP 
emissions from EGUs. We do not believe that is a reasonable 
interpretation of the statute, and the Agency did not interpret the 
statute in that manner when it conducted the Utility Study. In Chapter 
13 of the Utility Study, the EPA considered a range of control measures 
that would reduce the different types of HAP emitted from EGUs. http://www.epa.gov/ttn/atw/combust/utiltox/eurtc1.pdf. The EPA considered pre-
combustion controls such as coal washing, fuel switching, and 
gasification; combustion controls such as boiler design; post-
combustion controls such as fabric filters, scrubbers, and carbon 
absorption; and alternative controls strategies such as demand-side 
management, energy conservation, and use of alternative fuels (e.g., 
biomass) or renewable energy. The options discussed in the Utility 
Study for controlling HAP emissions from EGUs are almost universally 
available to comply with a CAA section 112(d) standard.
    Given the manner in which the Agency conducted the Utility Study, 
the EPA interpreted the statutory direction as a requirement to set 
forth the potential alternative control options available to EGUs to 
comply with CAA section 112 standards in the event the Agency 
determined regulation under section 112 was appropriate and necessary. 
The EPA's development and discussion in the Utility Study of 
alternative control strategies for complying with the standards would 
help prepare EGUs to comply with the standards if promulgated. Thus, 
the EPA interpreted the direction to address control strategies in the 
Utility Study as a request to identify the controls available to EGUs 
for addressing HAP emissions, and such information would, of course, be 
relevant if EPA determined that such emissions warranted regulation 
under section 112.
    Furthermore, the EPA establishes CAA section 112(d) standards for 
stationary sources and it is the responsibility of the sources to 
comply with the standards using any mechanism available, including pre-
combustion and post-combustion measures. Also, the establishment of a 
MACT standard under CAA section 112(d)(2) and (3) is a two-step 
process. In the first step, the Agency establishes a floor based on the 
performance of the best controlled unit or units. See CAA section 
112(d)(3). In the second step, the Agency must consider additional 
measures that may reduce HAP emissions and adopt such measures if 
reasonable after considering costs and non-air quality health and 
environmental effects. See CAA section 112(d)(2). Under the second 
step, the Agency can consider any measure that reduces HAP emissions 
even if no source in the category is employing the option under 
consideration. So, even under the commenter's flawed interpretation of 
``alternative control strategies'', the direction in CAA section 
112(n)(1)(A) is not a ``pointless exercise'' for the development of CAA 
section 112(d) standards as the Agency considers relevant technologies 
and HAP emission reduction approaches in evaluating whether to set a 
more stringent beyond the floor standard.
    Comment: One commenter points to CAA section 307(d)(1)(C) and notes 
that CAA section 112(n) is listed among the provision for which the 
rulemaking requirements of CAA 307(d) apply. Commenter maintains that 
this inclusion creates an expectation under the statute that EPA may 
establish regulatory standards under CAA 112(n). The commenter points 
to CAA sections 112 (n)(1), (n)(3), and (n)(5) and states that those 
provisions specifically discuss regulation under CAA section 112 and 
that EPA must explain why CAA 307(d)(1)(C) states ``any regulation 
under'' CAA 112(n) to defend regulation of utilities under section 
112(d). The commenter then implies that EPA erred by not even 
mentioning this provision at proposal.
    The commenter also takes issue with EPA's statement in the proposed 
rule that ``use of the terms section, subsection, and subparagraph'' 
``demonstrates that Congress was consciously distinguishing the various 
provisions of section 112 in directing the conduct of the study and the 
manner in which the Agency must regulate EGUs,'' if EPA determines that 
it is appropriate and necessary to regulate EGUs. See 76 FR at 24,993/
2.
    One commenter does not agree with the EPA's finding that the word 
``subsection'' in the first sentence of CAA section 112(n)(1)(A) 
demonstrates that Congress was consciously distinguishing between the 
various provisions of CAA section 112 in directing the conduct of the 
study and the manner in which the Agency must regulate EGUs,'' were the 
EPA to ``find[ ] it appropriate and necessary to do so.'' See 76 FR 
24993/2. According to the commenter, the only evident reason that the 
word ``subsection'' is used in the first sentence of CAA section 
112(n)(1)(A) is because the reference is made to the ``pollutants'' 
which the Utility Study is to address--i.e., the ``pollutants'' that 
are emitted by EGUs and which are ``listed under subsection (b)'' of 
CAA section 112. Similarly, the word ``subparagraph'' is used in the 
last sentence of CAA section 112(n)(1)(A) to identify ``the study'' 
which the EPA is directed to undertake by subparagraph (A) of CAA 
section 112(n)(1)--i.e., the Utility Study. That the last sentence of 
subparagraph (n)(1)(A) also states that EPA ``shall regulate electric 
utility steam generating units under this section'' does not even 
imply--much less expressly communicate--that regulation ``under this 
section'' must mean ``regulation under section 112(d).'' The commenter 
stated that Congress was ``consciously distinguishing'' between the 
``various provisions of section 112'' for the sake of clarity in the 
drafting of CAA section 112(n).
    The commenter also asserts that the EPA mistakenly relies on 
section 112(c)(6) when the EPA states that `` `where Congress wished to 
exempt EGUs from specific requirements of section 112, it said so 
explicitly. Congress did not exempt EGUs from the other requirements of 
section 112,' '' and thus the Agency is `` `required to establish 
emission standards for EGUs consistent with the requirements set forth 
in section 112(d)' '' (citing 76 FR at 24,993 (internal quotation 
omitted)).
    According to the commenter, nothing in section 112(c)(6) indicates 
how (or even whether) EGU HAP emissions should be regulated under 
section 112; paragraph (c)(6) serves only to reiterate that the 
regulation of such emissions is to occur (if at all) as is provided by 
section 112(n)(1). The commenter also asserts that the EPA mistakenly 
relies on New Jersey. According to the commenter, the D.C. Circuit in 
that case did not indicate that the language of section 112(c)(6) 
should, or could, be construed to mean that EGUs must be regulated 
under a MACT standard adopted pursuant to section 112(d).
    Response: The commenter makes a number of arguments that appear to 
take issue with the EPA's determination that EGUs should be regulated 
under CAA section 112(d) if the Agency determines that regulation of 
HAP emissions from such units is appropriate and necessary.

[[Page 9332]]

The commenter implies that the EPA erred because alternative mechanisms 
for regulation of EGUs under CAA section 112 might exist. We do not 
agree.
    The commenter's argument that the EPA erred because we did not 
explain why section CAA section 307(d)(1)(C) contemplates regulations 
under CAA section 112(n) is without merit. It is correct that the 
Agency believes EGUs should be regulated in the same manner as other 
sources if the appropriate and necessary finding is made because of the 
structure of CAA section 112. Nothing in CAA section 112(n)(1) requires 
or implies that the Agency should or must establish standards for EGUs 
under that provision. Furthermore, unlike CAA sections 112(n)(3) and 
112(n)(5) that commenter cites, CAA section 112(n)(1)(A) does not 
provide any guidance concerning the manner in which EPA is authorized 
or required to regulate sources under CAA section 112. See CAA section 
112(n)(3) (specifically authorizing identified control measures and 
other requirements for consideration in issuing standards under CAA 
section 112); see also CAA section 112(n)(5) (directing the Agency to 
develop and implement a control strategy for emissions of hydrogen 
sulfide using any authority available under the CAA, including sections 
112 and 111, if regulation is appropriate). For these reasons, we 
disagree that any error occurred because we did not specifically 
discuss in this proposed rule whether we could or should regulate EGUs 
under CAA section 112(n)(1) instead of CAA section 112(d).\63\ The 
Agency validly listed EGUs in 2000 and listed sources must be regulated 
pursuant to CAA section 112(d).
---------------------------------------------------------------------------

    \63\ We note that in our January 2004 proposed rule, we 
solicited comment on whether section 112(n)(1)(A) provided 
independent authority to regulate EGUs. We received several comments 
on this issue, and we rejected the concept after reviewing the 
comments and further considering the language of section 
112(n)(1)(A) and the structure of section 112. As such, we proposed 
and are finalizing that once the Agency determines that it is 
appropriate and necessary to regulate EGUs under section 112, those 
sources are listed pursuant to subsection 112(c), as we did in 
December 2000, and the Agency must set standards for those sources 
pursuant to section 112(d). See section 112(c) and (d)(1) (requiring 
establishment of 112(d) standards for listed source categories).
---------------------------------------------------------------------------

    Even if we agreed that regulation under CAA section 112(n)(1) was a 
viable option for EGUs, we would still have listed and regulated EGUs 
like other sources because CAA section 112(d) provides a statutory 
framework for regulating HAP emissions from sources and CAA section 
112(n)(1) does not. We believe that even if CAA section 112(n)(1) were 
available to regulate EGUs, there would be sufficient uncertainty about 
the legal vulnerability of such an approach to caution against 
employing it. This legal uncertainty would be particularly troubling in 
light of the fact that we have identified hazards to public health and 
the environment from HAP emissions from EGUs that warrant regulation, 
and these regulations are long overdue.
    The commenter also takes issue with our statement in the preamble 
to the proposed rule that the use of the words ``section'', 
``subsection'', and ``subparagraph'' in CAA section 112(n)(1)(A) 
``demonstrates that Congress was consciously distinguishing the various 
provisions of section 112 in directing the conduct of the study and the 
manner in which the Agency must regulate EGUs.'' See 76 FR 24993. The 
commenter appears to make much of our use of the word ``must'' in that 
sentence and also states that our interpretation of the significance of 
the use of the three terms in CAA section 112(n)(1)(A) is flawed 
because Congress only used the three terms for purposes of clarity. The 
commenter is incorrect on both points. With respect to the commenter's 
concern regarding the use of the word ``must'' in the sentence quoted 
above, we note that in the next sentence we stated that ``Congress 
directed the Agency to regulate utilities `under this section,' and 
accordingly EGUs should be regulated in the same manner as other 
categories for which the statute requires regulation.'' Id. (emphasis 
added). We were not foreclosing the possibility of any alternative 
interpretation and our use of the term ``must'' should not detract from 
the point we were trying to make. Specifically, we believe that 
Congress would have directed us to regulate EGUs under CAA section 
112(n)(1)(A) if that was its intent and, absent that mandate, the 
better reading of the statute is the one provided in the preamble to 
the proposed rule, which is that EGUs should be listed pursuant to CAA 
section 112(c) and subject to CAA section 112(d) emission standards.
    The commenter also stated that the EPA relied on CAA section 
112(c)(6) to support a conclusion that EGUs must be regulated under CAA 
section 112(d). The commenter takes the EPA's statements out of 
context. The statement in whole read:

    Furthermore, the D.C. Circuit Court has already held that 
section 112(n)(1) ``governs how the Administrator decides whether to 
list EGUs'' and that once listed, EGUs are subject to the 
requirements of CAA section 112. New Jersey, 517 F.3d at 583. 
Indeed, the D.C. Circuit Court expressly noted that ``where Congress 
wished to exempt EGUs from specific requirements of section 112, it 
said so explicitly,'' noting that ``section 112(c)(6) expressly 
exempts EGUs from the strict deadlines imposed on other sources of 
certain pollutants.'' Id. Congress did not exempt EGUs from the 
other requirements of CAA section 112, and once listed, EPA is 
required to establish emission standards for EGUs consistent with 
the requirements set forth in CAA section 112(d), as described 
below. See 76 FR 24993.

    As can be seen from this passage, the Court cited section 112(c)(6) 
as an example of Congress' intent regarding regulating EGUs under CAA 
section 112. The commenter cited the last clause of the last sentence 
of the paragraph quoted above without including the prefatory clause 
``once listed,'' and, without that clause, the statement is not fairly 
characterized. The point the EPA was making in that paragraph is that 
EGUs are a listed source category and listed sources must be regulated 
under CAA section 112(d) unless the EPA delists the source category.
    Comment: One commenter stated that EPA overstates the significance 
of the D.C. Circuit's holding in New Jersey by suggesting that the 
decision mandates EGU regulation under CAA section 112(d) because EGUs 
``remain listed'' under CAA section 112(c), See New Jersey, 517 F.3d at 
582. According to the commenter, the court declined to address the 
lawfulness of EPA's having ``listed'' EGUs under CAA section 112(c), 
leaving that matter to be decided if and when EPA adopted standards for 
EGUs under CAA section 112. Nowhere in the decision did the D.C. 
Circuit indicate that EPA must regulate EGUs under CAA section 112(d).
    According to the commenter, the EPA must consider both whether the 
regulation of EGUs is ``appropriate and necessary'' under section 
112(n)(1) and address anew whether the Agency is authorized by section 
112 to list EGUs under section 112(c) at all. The commenter asserts 
that on the face of the proposal, the EPA has not revisited the 
question whether the ``listing'' of EGUs under section 112(c) is 
consistent with congressional intent.
    Response: The commenter's arguments are circular and it is 
difficult to fully determine exactly what its issue is with EPA's 
listing; however, it appears that the commenter believes that EPA 
incorrectly relied on the New Jersey decision to justify the listing of 
EGUs. The commenter also appears to argue that the Agency has never 
explained why it has the authority to list EGUs at all. We disagree.
    As stated in the preamble to the proposed rule, CAA section 
112(n)(1)(A)

[[Page 9333]]

requires EPA to conduct a study of HAP emissions from EGUs and regulate 
EGUs under CAA section 112 if we determine that regulation is 
appropriate and necessary, after considering the results of the study. 
76 FR 24981, 24986, and 24998. The only condition precedent to 
regulating EGUs under CAA section 112 is a finding that such regulation 
is appropriate and necessary (after conducting and considering the 
Utility Study), and once that finding is made the Agency has the 
authority to list EGUs under CAA section 112(c) as the first step in 
the process of establishing regulations under section 112. The D.C. 
Circuit agrees with that interpretation of the statute as evidenced by 
its statement in New Jersey that ``section 112(n)(1)(A) governs how the 
Administrator decides whether to list EGUs for regulation under section 
112,'' 517 F.3d at 582, and the Court's statement directly contradicts 
the commenter's position.
    The EPA did not rely on the New Jersey decision to justify the 
appropriate and necessary finding as the commenter suggests. We based 
the finding in 2000 on the extensive information available to the 
Agency at the time, and we confirmed the finding in the preamble to the 
proposed rule based on new information. The commenter had ample 
opportunity to comment on the appropriate and necessary finding, and it 
may challenge the basis of the listing (i.e. the appropriate and 
necessary finding) when EPA issues the final standards.
    Comment: One commenter believes that the D.C. Circuit will condemn 
the final rule as a result of EPA's ``misapprehension'' that upon 
making an ``appropriate and necessary'' finding, the Agency is 
compelled by the CAA to adopt a regulatory standard for EGUs under CAA 
section 112(d). According to the commenter, a regulation will be 
invalid if the regulation `` `was not based on the [agency's] own 
judgment' '' but `` `rather on the unjustified assumption that it was 
Congress' judgment that such [a regulation] is desirable' or 
required.'' See Transitional Hospitals Corp. v. Shalala, 222 F.3d 1019, 
1029 (D.C. Cir. 2000), quoting Prill v. NLRB, 755 F.2d 941, 948 (D.C. 
Cir. 1985). The commenter further notes that the D.C. Circuit has held 
that, where an agency wrongly construes a judicial decision as 
compelling a particular statutory interpretation, and thereby unduly 
limits the scope of its own discretion, the agency's action cannot be 
sustained. See, e.g., Phillips Petroleum Co. v. FERC, 792 F.2d 1165, 
1171 (D.C. Cir. 1986). The commenter believes the rule is bound to be 
rejected and that the EPA should ``reconsider the legal interpretations 
on which it purports to base its rule.''
    Response: We do not agree that we have improperly interpreted the 
statute as limiting our discretion in the manner suggested by the 
commenter. The commenter makes only one specific allegation in this 
comment and that concerns the Agency's conclusion that it must 
establish CAA section 112(d) standards for EGUs in light of the New 
Jersey decision. The commenter does not explain why that conclusion is 
incorrect. As we state above and in the preamble to the proposed rule, 
because EGUs are a CAA section 112(c) listed source category, the 
Agency must establish CAA section 112(d) standards or delist EGUs 
pursuant to CAA section 112(c)(9). See New Jersey, 517 F.3d at 582-83 
(holding that EGUs remain listed under section 112(c)); see also CAA 
section 112(c)(2) (requiring the Agency to ``establish emission 
standards under subsection [112] (d)'' for listed source categories and 
subcategories); 76 FR 24998-99. We concluded in the preamble to the 
proposed rule that we could not delist EGUs because our appropriate and 
necessary analysis showed that EGUs did not satisfy the CAA section 
112(c)(9)(B)(i) delisting criteria. Id. We did not address in the 
preamble to the proposed rule whether EGUs satisfied the CAA section 
112(c)(9)(B)(ii) criteria because EGUs failed the first prong of the 
delisting provisions. Id. We reach the same conclusion in the final 
rule and also address the delisting petition submitted by this 
commenter. Because we cannot delist EGUs, we must regulate them under 
CAA section 112(d). The commenter has provided no legitimate argument 
to rebut this conclusion. See also previous responses regarding 
regulation under section 112(n)(1)(A).
    Comment: One commenter alleges that EPA impermissibly relied on CAA 
section 112(c)(9) to interpret ``hazards to public health'', and argues 
that the ``residual risk'' provisions in CAA section 112(f)(2) are more 
appropriate for the establishment of standards for EGUs. The commenter 
stated that by using CAA section 112(c)(9)(B)(i) in defining ``hazards 
to public health'', the Agency has seized on the one interpretation of 
the phrase that is surely contrary to congressional intent and, thus, 
falls outside the permissible range of its interpretative discretion. 
The commenter maintains that the ``delisting'' criteria of CAA section 
112(c)(9) are simply irrelevant to the decision whether EGU HAP 
emissions will present any ``hazards to public health'' sufficient to 
warrant regulation of those emissions under CAA section 112.
    The commenter also argues that Congress intended that EGUs be 
treated differently from all other ``major sources'' to which the 
``delisting'' provisions of CAA section 112(c)(9), and the standard-
setting provisions of CAA section 112(d) necessarily and automatically 
apply. Therefore, according to the commenter, the EPA's proposal to 
utilize the criteria of CAA section 112(c)(9) to inform its findings 
under CAA section 112(n)(1)(A) treats EGUs exactly the same as all 
other major source categories, is contrary to congressional intent, and 
thus unlawful. The commenter goes on to state that in exercising its 
discretion to define ``hazards to public health'' as the phrase is used 
in CAA section 112(n)(1)(A), the EPA would be better served to consider 
the ``residual health risk'' provisions of CAA section 112(f)(2). Those 
provisions provide a better analogy to the establishment of standards 
for EGUs under CAA section 112 than do the ``de-listing'' criteria of 
CAA section 112(c)(9).
    The commenter believes the category-specific criteria of paragraph 
(c)(9) are a poor fit for an evaluation of ``hazards to public health'' 
that should reasonably include such factors as the affected population, 
the characteristics of exposure, the nature of the health effects, and 
the uncertainties associated with the data. The commenter states that, 
while CAA section 112(n)(1)(A) does not expressly include any 
requirement that EGU emissions be regulated with an ``ample margin of 
safety,'' that standard is more appropriate than the ``one-in-a-
million'' cancer risk standard of CAA section 112(c)(9)(B)(i) that EPA 
proposes to employ.
    Response: The commenter acknowledges that EPA has broad discretion 
to interpret the phrase ``hazard to public health'' but argues that the 
one thing we cannot do is use the CAA section 112(c)(9)(B) delisting 
provisions as a benchmark in making that interpretation. The commenter 
asserts that the use of the delisting standard is clearly contrary to 
Congressional intent but it does not provide any substantive rebuttal 
to our conclusion that the CAA section 112(c)(9) standards reflects the 
level of hazard which Congress concluded warranted continued 
regulation. Instead, the commenter reverted to its argument that the 
statute treated EGUs differently. The EPA views the disparate treatment 
of EGUs in a different light than commenter. While it is true that 
Congress established a different

[[Page 9334]]

statutory provision governing whether to add EGUs as a regulated source 
category under section 112, we do not interpret CAA section 
112(n)(1)(A) as providing Congressional license to ignore risks that 
Congress determined warranted regulation for all other source 
categories. Because CAA section 112(c)(9) defines that level of risk, 
it is reasonable to consider it when evaluating whether EGU HAP 
emissions pose hazards to public health.
    The commenter also suggests that the ``ample margin of safety 
standard'' of CAA section 112(f)(2) is a better fit than the one-in-a-
million standard set forth in CAA section 112(c)(9)(B)(1) for 
evaluating hazards to public health. The commenter asserts that an 
evaluation of ``hazards to public health'' should include such factors 
as the affected population, the characteristics of exposure, the nature 
of the health effects, and the uncertainties associated with the data. 
However, the EPA did not rely solely on the delisting provisions for 
evaluating hazards to public health as commenter suggests. In fact, the 
EPA considered all of the factors the commenter suggests in making our 
finding.\64\ Thus, we decline to adjust our approach to evaluating 
hazards to public health and the environment based on the comments.
---------------------------------------------------------------------------

    \64\ 76 FR 24992.
---------------------------------------------------------------------------

h. 2000 Finding (and 2005 Delisting)
    Comment: Several commenters generally support EPA's 2000 finding 
that regulating HAP emissions from EGUs under CAA section 112 is 
``appropriate and necessary.'' According to the commenters, the 2000 
finding was proper under the CAA and within EPA's discretion, well-
supported based on sound science available to the Agency at the time on 
the harm from HAP emitted by EGUs, and no additional information makes 
the finding invalid. Several commenters cited the conclusions of the 
Utility Study \65\ and Mercury Study,\66\ which they assert supported 
the finding and satisfied the only prerequisite for the finding. One 
commenter specifically asserted that the 2000 finding was well-
supported by the Utility Study's conclusions that (1) there was a link 
between anthropogenic Hg emissions and MeHg found in freshwater fish, 
(2) Hg emissions from coal-fired utilities were expected to worsen by 
2010, and (3) MeHg in fish presents a threat to public health from fish 
consumption. One commenter noted that the CAA does not require a 
conclusive link between HAP emissions and harm. One commenter stated 
that the CAA grants the Administrator discretion in her finding, and 
that discretionary decision should not be overly scrutinized, citing 
court opinion.\67\ In support of the finding, one commenter stated that 
it would not make sense for Congress to limit HAP emissions from small 
businesses such as dry cleaners but to exempt U.S. EGUs, which are the 
largest sources of many HAP emissions. One commenter agreed that 
finding was further supported because numerous control options were 
available to reduce HAP emissions. One commenter agreed with the 2000 
finding that the Agency lacked sufficient evidence to conclude that 
non-Hg HAP from EGUs posed no hazard.
---------------------------------------------------------------------------

    \65\ U.S. EPA 1998. Study of Hazardous Air Pollutant Emissions 
from Electric Utility Steam Generating Units--Final Report to 
Congress. EPA-453/R-98-004a. February.
    \66\ U.S. EPA, 1997.
    \67\ ``Where a statute is precautionary in nature, the evidence 
difficult to come by, uncertain, or conflicting because it is on the 
frontiers of scientific knowledge, the regulations designed to 
protect the public health, and the decision that of an expert 
administrator, [courts] will not demand rigorous step-by-step proof 
of cause and effect.'' Ethyl Corp. v. EPA, 541 F.2d 1, 28 (Ct. App. 
D.C. Circ. 1978).
---------------------------------------------------------------------------

    The commenters who generally supported the 2000 finding also 
commented on specific aspects of the finding. Several commenters 
asserted that while the evidence on Hg alone supports the finding, the 
potential harm from non-Hg HAP further supported the 2000 finding. 
Several commenters noted that new science continues to support the 2000 
finding. Several commenters also stated that the ``appropriate'' 
finding was further supported because numerous control options were 
available at the time of the finding that would reduce HAP emissions. 
One commenter concurred with EPA that regulating natural gas-fired EGUs 
was not appropriate and necessary because the impacts due to HAP 
emissions from such units are negligible based on the results of the 
Utility Study.
    Several commenters addressed the 2005 reversal of the 2000 finding. 
Several commenters specifically supported the vacatur of the 2005 
action. Other commenters asserted that the 2005 action was proper, and 
that EPA reverted back to the 2000 finding in the proposed rule without 
adequate explanation or support. Several commenters cited the 2005 
action as invalidating the 2000 finding, specifically noting that EPA 
concluded that ``no hazards to public health'' remained after 
accounting for emission reductions under CAIR. These commenters assert 
that EPA's current position is illegal because EPA took the exact 
opposite position on the interpretation of the term ``necessary'' in 
its 2005 reversal, and, thus, deserves no judicial deference. One 
commenter stated that in 2005 EPA recognized the potential for 
excessive regulation created by CAA section 112 and determined that the 
2000 finding lacked foundation.
    Several commenters generally disagreed with the 2000 finding, with 
two commenters stating that EPA did not have a rational justification 
for it and another claiming that it was fraught with misinformation and 
overestimating assumptions. One commenter claimed that EPA did not 
explain the terms ``appropriate'' and ``necessary'' in the 2000 finding 
and that the emission control analysis was inadequate. Two commenters 
stated that the 2000 finding was based on data that was more than 10 
years old, which causes serious concern regarding the validity of the 
findings because technology, the regulatory environment, and the 
economic climate have evolved. Furthermore, because the Utility Report 
underestimated emissions controls that EGUs would install by 2010 and 
additional controls that would be later required by the CSAPR, the 
basis for EPA's 2000 finding has changed. Several commenters stated 
that a ``plausible link'' between anthropogenic Hg and MeHg in fish is 
not an adequate reason for the 2000 finding. Several commenters claim 
that EPA only identified health concerns for Hg (and potentially Ni) 
but not other HAP from coal-fired EGUs in the 2000 finding, and, thus, 
cannot regulate HAP other than Hg because the 2000 finding authorizes 
only the regulation of Hg. One commenter questioned the Hg emissions 
underlying the 2000 finding, specifically the fraction of total 
deposition attributable to U.S. EGUS and the fact that EPA projected an 
increase in U.S. EGU emissions from 1990 to 2010 though emissions 
actually declined.
    Several commenters raised procedural issues related to the 2000 
finding. Several commenters stated that the 2000 finding failed to 
provide public notice and comment. According to the commenters, the CAA 
requires that any decision made under CAA section 112(n) must go 
through public notice and comment. The commenters further stated that 
the failure to provide public notice and comment means that this MACT 
is outside EPA's statutory authority. One commenter stated that because 
the 2000 finding was never ``fully ventilated'' in front of the D.C. 
Circuit, the EPA's authority to regulate EGUs under CAA section 112(d) 
is directly at issue. The commenters claim that specific issues did not 
undergo

[[Page 9335]]

public notice and comment, including least-cost regulatory options, the 
impact of regulation on electricity reliability, and EPA's 
interpretation of the requirements under CAA section 112(n)(1)(A). One 
commenter claims that EPA attempted to provide after-the-fact support 
for its 2000 finding with new legal analysis and new factual 
information, contrary to New Jersey v. EPA that held that EPA may not 
revisit its 2000 finding except through delisting under CAA section 
112(c)(9). One commenter stated that EPA's 2000 finding should be 
reviewed when EPA issues the actual NESHAP.\68\ One commenter stated 
that the 2000 finding ignored EO 12866.
---------------------------------------------------------------------------

    \68\ See UARG v. EPA, 2001 WL 936363, No. 01-1074 (D.C. Cir. 
July 26, 2001).
---------------------------------------------------------------------------

    Response: EPA agrees with the commenters that the 2000 finding was 
reasonable and disagrees with the commenters asserting that the 2000 
finding was unreasonable or failed to follow proper procedural 
requirements.
    The EPA agrees that reviewing courts defer to the reasoned 
scientific and technical decisions of an Agency charged with 
implementing complex statutory provisions such as those at issue in 
this case. As EPA stated in the preamble to the proposed rule, the EPA 
maintains that the 2000 finding was reasonable and based on well-
supported evidence available at the time, including the Utility Study, 
the Mercury Study,\69\ and the NAS study,\70\ which all showed the 
hazards to public health and the environment from HAP emitted from 
EGUs. New technical analyses conducted by EPA confirm that it remains 
appropriate and necessary to regulate HAP emissions from EGUs. 
Furthermore, the EPA agrees with the commenters on several points 
raised, specifically that EGUs were and remain the largest 
anthropogenic source of several HAP in the U.S., that risk assessments 
supporting the 2000 finding indicated potential concern for several 
non-Hg HAP, and that several available control options would 
effectively reduce HAP emissions from U.S. EGUs.
---------------------------------------------------------------------------

    \69\ U.S. EPA, 1997.
    \70\ NAS, 2000.
---------------------------------------------------------------------------

    The EPA agrees with the commenters that Congress did not exempt 
EGUs from section 112(d) HAP emission limits while simultaneously 
limiting emissions at other sources with less HAP emissions. Congress 
simply provided EPA with a separate path for listing EGUs by requiring 
that the Agency evaluate HAP emissions from EGUs and determine whether 
regulation under CAA section 112 was appropriate and necessary. Since 
1990, the EPA has promulgated regulations requiring the use of 
available control technology and other practices to reduce HAP 
emissions for more than 170 source categories. U.S. EGUs are the most 
significant source of HAP in the country that remains unaddressed by 
Congress's air toxics program. The EPA listed EGUs in 2000 because the 
considerable amount of available data supported the conclusion that 
regulation of EGUs under CAA section 112 was appropriate and necessary. 
That finding was valid at the time, and EPA reasonably added EGUs to 
the CAA section 112(c) list of sources that must be regulated under CAA 
section 112.
    The EPA acknowledges that we did not expressly define the terms 
appropriate and necessary in the 2000 finding, but the finding is 
instructive in that it shows that EPA considered whether HAP emissions 
from EGUs posed a hazard to public health and the environment and 
whether there were control strategies available to reduce HAP emissions 
from EGUs when determining whether it was appropriate to regulated 
EGUs.\71\ When concluding it was necessary, the Agency stated that 
imposition of the requirements of the Act would not address the 
identified hazards to public health or environment from HAP emissions 
and that section 112 was the proper authority to address HAP 
emissions.\72\ The EPA explained in the preamble to the proposed rule 
its conclusion that the 2000 finding was fully supported by the 
information available at the time,\73\ and EPA stands by the 
conclusions in that notice. Furthermore, the EPA provided an 
interpretation of the terms appropriate and necessary that is wholly 
consistent with the 2000 finding. The EPA does not agree with the 
commenters that a quantification of emissions reductions or a specific 
identification of the available controls was necessary to support the 
2000 finding and listing. The EPA considered the Utility Study when 
making the finding, and that study clearly articulated the various 
alternative control strategies that EGUs could employ to control HAP 
emissions.\74\ As to emission reductions, the EPA cannot estimate the 
level of HAP emission reductions until the Agency proposes a CAA 
section 112(d) standard after a source category is listed.
---------------------------------------------------------------------------

    \71\ 65 FR 79830.
    \72\ Id.
    \73\ 65 FR 24994-24996.
    \74\ See Chapter 13 of the Utility Study (U.S. EPA, 1998).
---------------------------------------------------------------------------

    The EPA disagrees with commenters that suggest it was not 
``rational'' to determine that it was appropriate to regulate HAP 
emissions from EGUs due to the cancer risks identified in the Utility 
Study or the potential concerns associated with other HAP emissions 
from EGUs. Nothing in CAA section 112(n)(1)(A) suggests that EPA must 
determine that every HAP emitted by EGUs poses a hazard to public 
health or the environment before EPA can find it appropriate to 
regulate EGUs under CAA section 112. In fact, the EPA maintains that it 
must find it appropriate and necessary to regulate EGUs under CAA 
section 112 if it determines that any one HAP emitted from EGUs poses a 
hazard to public health or the environment that will not be addressed 
through imposition of the requirements of the Act. The EPA disputes the 
commenters' conclusion that the 2000 finding was limited to Hg and Ni 
emissions, but, even if it were, the EPA reasonably concluded that EGUs 
should be listed pursuant to CAA section 112(c) based on the Hg and Ni 
finding. As stated in the 2000 finding, cancer risks from some non-Hg 
metal HAP (including As, Cr, Ni, and Cd) were not low enough to be to 
eliminate as potential concern.\75\ Source categories listed for 
regulation under CAA section 112(c) must be regulated under CAA section 
112(d), and the D.C. Circuit has stated that EPA has a ``clear 
statutory obligation to set emission standards for each listed HAP''. 
See Sierra Club v. EPA, 479 F.3d 875, 883 (D.C. Cir. 2007), quoting 
National Lime Association v. EPA, 233 F.3d 625, 634 (D.C. Cir. 2000). 
Therefore, even if EPA concluded that CAA section 112(n)(1) authorized 
a different approach for regulating HAP emissions from EGUs, the chosen 
course which is supported by the CAA (i.e., listing under CAA section 
112(c)) requires the Agency to regulate under CAA section 112(d) 
consistent with the statute and case law interpreting that provision.
---------------------------------------------------------------------------

    \75\ 76 FR 79827.
---------------------------------------------------------------------------

    The EPA disagrees that there is any concern regarding the validity 
of the 2000 finding or that the emissions information provided in the 
2000 finding makes the finding ``questionable'' as stated by some of 
the commenters. The EPA maintains that the 2000 finding was sound and 
fully supported by the record available at the time, including the 
future year emissions projections. Therefore, the listing of EGUs is 
valid based on that finding alone. Even though Hg emissions have 
decreased since the 2000 finding instead of increasing as projected, 
the new technical analyses confirm that Hg emissions from EGUs continue 
to pose hazards to public

[[Page 9336]]

health and the environment. The EPA also indicated potential concern 
for several non-Hg HAP in the 2000 finding. It is well established that 
even small amounts of HAP can cause significant harm to human health 
and the environment.
    The EPA agrees with the commenters who assert that the 2005 action 
was in error and disagrees with the commenters that the 2005 action 
invalidated the 2000 finding. As fully described in the preamble to the 
proposal, the EPA erred in the 2005 action by concluding that the 2000 
finding lacked foundation. The 2005 action improperly conflated the 
``appropriate'' and ``necessary'' analyses by addressing the ``after 
imposition of the requirements of the Act'' in the appropriate finding 
as well as the necessary finding. The EPA also indicated that it was 
not reasonable to interpret the necessary prong of the finding as a 
requirement to scour the CAA for alternative authorities to regulate 
HAP emissions from stationary sources, including EGUs, when Congress 
provided section 112 for that purpose. The EPA asserts that the 2000 
finding was sound and fully supported by the record available at the 
time for all the reasons stated in this final rule and the proposed 
rule. The 2005 action interpreted the statute in a manner inconsistent 
with the 2000 finding and attempted to delist EGUs without complying 
with the mandates of CAA section 112(c)(9)(B). See New Jersey, 517 F.3d 
at 583 (vacating the 2005 ``delisting'' action). In the preamble to the 
proposed rule, the EPA set forth a revised interpretation of CAA 
section 112(n)(1) that is consistent with the statute and the 2000 
finding. The EPA also explained in the preamble to the proposed rule 
why the 2005 action was not technically or scientifically sound. The 
EPA specifically addressed the errors associated with the 2005 action 
in the preamble to the proposed rule, and commenters' assertions do not 
cause us to revisit these issues. The commenter is also incorrect in 
suggesting that a change in interpretation is per se invalid and 
provided no support for that position. See National Cable & 
Telecommunications Ass'n, et al., v. Brand X Internet Services, et al., 
545 U.S. 967, 981 (discussing the deference provided to an Agency 
changing interpretations, the Court stated ``change is not 
invalidating, since the whole point of Chevron deference is to leave 
the discretion provided by ambiguities of a statute with the 
implementing Agency.'') (Internal citations and quotations omitted).
    The EPA disagrees with the commenters who raise concerns about the 
validity of the 2000 finding because the data on which that finding was 
based were more than 10 years old. The EPA made the finding at that 
time based on the scientific and technical information available, and 
the finding is wholly supported by that information. In addition, even 
though not required to do so, the EPA has since conducted new technical 
analyses utilizing the best information available in 2010 as several 
years have passed since the 2000 finding. These new analyses confirm 
that HAP emissions from EGUs continue to pose a hazard to public health 
and the environment, even after taking into account emission reductions 
that have occurred since 2000 from promulgated rules, settlements, and 
consent decrees. See 76 FR 24991.
    Contrary to the commenter's assertion, the EPA did not violate CAA 
section 307(d) by not providing a notice and comment opportunity before 
making the December 2000 appropriate and necessary finding. One 
commenter challenged EPA's 2000 finding and listing on the same 
grounds, and the D.C. Circuit dismissed the case because CAA section 
112(e)(4) clearly states that listing decisions cannot be challenged 
until the Agency issues final emission standards for the listed source 
category. See UARG v. EPA, 2001 WL 936363, No. 01-1074 (D.C. Cir. July 
26, 2001). The EPA has provided the public an opportunity to comment on 
both the 2000 finding and the 2011 analyses that support the 
appropriate and necessary determination as part of the proposed rule, 
and anyone may challenge the listing in the D.C. Circuit in conjunction 
with a challenge to this final rule. The commenters could have also 
commented on the CAA section 112(n)(1) (e.g., the Utility Study and the 
Mercury Study) studies in 2000 as they were included in the docket, but 
EPA is not aware of any comments on those studies. In any case, these 
studies were peer reviewed and considered the best information 
available at that time. The EPA has fully complied with the rulemaking 
requirements of CAA section 307(d).
    The EPA also disagrees with the commenters' characterization of the 
New Jersey case. The D.C. Circuit did not say, as one commenter 
suggested, that EPA is not able to consider additional information that 
is collected after the 2000 finding; instead, the Court stated that EPA 
could not revise its appropriate and necessary finding and remove EGUs 
from the CAA section 112(c) list without complying with the delisting 
provisions of CAA section 112(c)(9). See New Jersey, 517 F.3d at 582-
83. The EPA also disagrees with the commenter's assertion that EPA 
disregarded EO 12866 when making the 2000 finding. As stated in the 
Federal Register notice, the 2000 finding did not impose regulatory 
requirements or costs and was reviewed by the Office of Management and 
Budget (OMB) in accordance with the EO.\76\
---------------------------------------------------------------------------

    \76\ 65 FR 79831.
---------------------------------------------------------------------------

2. New Technical Analyses
a. General Comments on New Technical Analyses
    Comment: Several commenters stated that the new analyses, including 
the risk assessments and technology assessments, confirm that it 
remains appropriate and necessary to regulate U.S. EGU HAP under CAA 
section 112. These commenters stated that the new analyses provide even 
more support than the risk and technology information available at the 
time the 2000 finding was made, including information on further 
developed emissions control technology, proven and cost-effective 
control of acid gases using trona and dry sorbent injection, stabilized 
natural gas prices that makes fuel switching and switching dispatch to 
underutilized combined cycle plants more feasible, more information on 
ecosystem impacts from HAP, ``hotspots'' from the deposition of Hg 
around EGUs, the potential for re-emission of Hg, updated emissions 
data and future projections of HAP emissions, and modern air pollution 
modeling tools. One commenter states affordable control technology has 
been in use in this sector for 10 to 40 years, and studies on EGU-
attributable Hg hazard has undergone two in-depth EPA reviews, as well 
as a review by the NAS. Several commenters claimed that regulating U.S. 
EGUs is appropriate and necessary to protect public health based on 
information provided in the new technical analyses. These commenters 
acknowledged the substantial reductions in HAP from recent regulations 
and new studies that confirm serious health risks from HAP exposure. 
One commenter stated that new studies show higher risks to fetuses than 
previously estimated, increasing the potential for neurodevelopmental 
effects in newborns. One commenter noted that EGUs are a major source 
of HAP, including HCl, HF, As, antimony, Cr, Ni, and selenium, all of 
which adversely affect human health. The commenter stated that because 
of these health effects, the EPA has ample evidence to support a 
determination

[[Page 9337]]

that non-Hg HAP emissions present a risk to human health.
    Other commenters disagreed that the new analyses confirm that it 
remains appropriate and necessary to regulate U.S. EGUs. One commenter 
claims that EPA tried to use the new technical analyses to provide 
retroactive justification for the 2000 finding, which only found 
``plausible links'' of health effects and ``potential concerns'' of 
health effects of certain metal emissions, dioxins and acid based 
aerosols. The commenter also asserted that none of these new analyses 
demonstrate that EGU regulation under section 112 is necessary and 
appropriate.
    One commenter agreed that EPA may supplement its finding with new 
information, analyses and arguments to reaffirm the 2000 finding up 
until EPA issues final emissions standards. The commenter noted that 
the CAA does not freeze the finding. However, another commenter argued 
that EPA does not have the authority to rely on new technical analyses 
because the CAA requires EPA to make the finding on the basis of the 
Utility Study alone. According to that commenter, the EPA unreasonably 
stretched the language of CAA section 112 by considering new technical 
analyses.
    Citing a report from Dr. Willie Soon that was submitted to the SAB, 
one commenter stated that the new technical analyses supporting the 
proposed rule do not conform to the Information Quality Act, which 
requires that information relied on by EPA be accurate, reliable, 
unbiased, and presented in a complete and unbiased manner.
    Response: The EPA agrees with the commenters that state that the 
new technical analyses (e.g., the risk assessments and technology 
assessment) confirm the 2000 finding and disagrees with the commenters 
that state otherwise. The EPA also agrees with the commenters that the 
2000 finding was valid at the time it was made based on the CAA section 
112(n)(1) studies and other information available to the Agency at that 
time. Furthermore, the EPA agrees with commenters that the final rule 
will lead to substantial reductions in HAP emissions from EGUs, that 
control of the HAP is estimated to lead to public health and 
environmental benefits as discussed in the RIA, that Hg emissions from 
U.S. EGUs pose a hazard to public health, and that non-Hg HAP emissions 
from EGUs pose a hazard to public health.
    Although these new analyses were not required, the EPA agrees with 
the commenters that stated that EPA is authorized to conduct additional 
analyses to confirm the 2000 finding. The EPA disagrees with the 
commenter's assertion that the Agency is not authorized to consider new 
information and at the same time unable to use the information 
available in 2000 because, according to the commenter, that information 
is ``stale.'' Under this theory, the Agency could not ever make an 
appropriate and necessary finding prospectively, thereby excusing the 
Agency from its obligations to protect public health and the 
environment because it did not diligently act in undertaking its 
statutory responsibility to establish CAA section 112(d) standards 
within two years of listing EGUs. See CAA section 112(c)(5). This is an 
illogical result that finds no basis in the statute. The EPA also 
disagrees with the commenter's assertion that EPA may not consider new 
analyses conducted after the Utility Study in determining whether it is 
appropriate and necessary to regulate EGUs under section 112 for the 
reasons set forth in the preamble to the proposed rule.\77\
---------------------------------------------------------------------------

    \77\ 76 FR 24988.
---------------------------------------------------------------------------

    The EPA disagrees with the commenter's implication that EPA 
conducted the new analyses because of alleged flaws in the 2000 
finding. As explained in detail in the preamble to the proposed rule, 
the 2000 finding was wholly valid and reasonable based on the 
information available to the Agency at that time, including the Utility 
Study. Further, the EPA maintains that had it complied with the 
statutory mandate to issue CAA section 112(d) standards within two 
years of listing EGUs, the EPA would likely have declined to conduct 
new analyses. The EPA conducted new analyses because over 10 years had 
passed since the 2000 finding, and EPA wanted to evaluate HAP emissions 
from U.S. EGUs based on the most accurate information available, though 
the Agency was not required to reevaluate the 2000 finding. In 
conducting the new analyses, the EPA used this updated information to 
further support the finding.
    The EPA strongly disagrees with the commenter that stated that EPA 
failed to conform to the Information Quality Act. The EPA used peer 
reviewed information and quality-assured data in all aspects of the 
technical analyses used to support the appropriate and necessary 
finding supporting this regulation. In addition, the EPA submitted the 
Hg Risk TSD to the SAB for peer review, which ``supports the overall 
design of and approach to the risk assessment and finds that it should 
provide an objective, reasonable, and credible determination of the 
potential for a public health hazard from mercury emitted from U.S. 
EGUs.'' \78\ The SAB received the comments from Dr. Willie Soon, and 
had those comments available for consideration in their deliberations 
regarding the Hg risk analysis. The SAB specifically supported elements 
of the analysis criticized by Dr. Willie Soon regarding the use of the 
EPA RfD as a benchmark for risk and the connection between Hg emissions 
from U.S. EGUs and MeHg concentrations in fish. In addition, the risk 
assessment methodology for the non-Hg case studies is consistent with 
the methodology that EPA uses for assessments performed for Risk and 
Technology Review rulemakings, which underwent peer review by the SAB 
in 2009. \79\ During the public comment period, the EPA also completed 
a letter peer review of the methods used to develop inhalation cancer 
risk estimates for Cr and Ni compounds, and those reviews were 
generally supportive. See above description of this peer review. For 
the final rulemaking, the EPA revised both risk assessments consistent 
with recommendations from the peer reviewers. The EPA relies on the 
SAB's review of the quality of the information supporting the 
analytical results. Accordingly, contrary to the commenters' 
assertions, the EPA acted consistently with the Information Quality Act 
as well as EPA's and OMB's peer review requirements.
---------------------------------------------------------------------------

    \78\ U.S. EPA-SAB, 2011.
    \79\ U.S. EPA-SAB, 2010.
---------------------------------------------------------------------------

b. Hg Emissions Estimates
1. Hg Emissions From EGUs
    Comment: The commenters addressed the 2005 and 2016 emissions 
estimates for Hg and expressed concern that inaccuracies in these 
emissions estimates result in overestimates of risks from Hg 
deposition. Further, commenters compared EPA's 2010 estimate and 2016 
estimate, and stated that it is not possible for 29 tons to be a 
correct inventory total for Hg emissions in both years given expected 
reductions from CSAPR. In addition, commenters specifically commented 
on assumptions included in the Integrated Planning Modeling (IPM), 
including a concern that Hg speciation factors used by IPM overestimate 
emissions in 2016. Other commenters noted that EGU sources are the 
predominant source of U.S. anthropogenic Hg emissions, particularly the 
oxidized and particulate forms of Hg that are of primary concern for Hg 
deposition.
    Response: The EPA disagrees with commenters' assertions that the 
EPA's

[[Page 9338]]

emissions estimates overestimate risk. While EPA agrees that the 2005 
Hg emissions may be overestimated, such an overestimate in 2005 would 
actually lead to an underestimate of risk in 2016 and not an 
overestimate of risk, as claimed by the commenter, because the ratio 
approach used by EPA to scale fish tissue data would underestimate risk 
if 2005 Hg estimates were overestimated. Since the 2005 emissions are 
not used as a starting point for 2016 emissions from IPM, any 2005 
overestimate does not affect the 2016 emissions levels. The 2016 
emissions are computed by IPM based on forecasts of demand, fuel type, 
Hg content of the fuel, and the emissions reductions resulting from 
each unit's configurations. See IPM Documentation for further 
information, which is available in the docket. No commenter has 
provided any evidence that the IPM 2016 emissions projection 
methodology resulted in an overestimate.
    The EPA acknowledges that the current Hg emissions estimate would 
not be the same as the 2016 Hg emissions estimate given that compliance 
with CSAPR is anticipated to have some Hg co-benefits. For this reason, 
the EPA reflected emission reductions anticipated from CSAPR in the Hg 
deposition modeling for 2016 in the Hg Risk TSD. In the final rule, the 
EPA revised the estimate of Hg emissions remaining from U.S. EGUs in 
2016, which includes additional emission reductions anticipated from 
the final CSAPR. The revised estimate shows that U.S. EGUs would emit 
27 tons of Hg in 2016. Although EPA does not use the current Hg 
emissions estimates in any of the risk calculations, the EPA estimates 
that current Hg emissions are 29 tons. Conclusions about the trend 
between current emissions and emissions in 2016 are limited by the fact 
that different methods were used to compute the two estimates, as fully 
explained in the revised Emissions Overview memo in the docket.
    The EPA disagrees with the commenter's assertion that incorrect Hg 
emission factors result in incorrect 2016 emissions. The 2016 projected 
Hg emissions are not based on emissions factors. The 2016 Hg emissions 
are computed by the IPM based on forecasts of demand, fuel type, Hg 
content of the fuel, and the emissions reductions resulting from each 
unit's configurations. The speciation factors referenced by the 
commenter provide a basis for the speciation of total projected Hg 
emissions into particulate, divalent gaseous, and elemental species, 
and do not impact the total amount of Hg emissions.
    The EPA agrees with commenters who noted that EGU sources are the 
predominant source of U.S. anthropogenic Hg emissions, and in 
particular the oxidized and particulate forms of Hg that are of primary 
concern for Hg deposition.
2. Global Hg Emissions
    Comment: Several commenters stated that predicted Hg deposition 
relies heavily on the amount of gaseous elemental Hg used to define the 
boundary and initial conditions of a model, e.g., the Hg that enters 
the U.S. from outside the U.S. boundaries. The commenters asserted that 
this is especially important because Hg emissions from Asia--the region 
immediately upwind of North America that affects U.S. Hg deposition 
significantly and also affects it the most compared to other regions--
are expected to continue to increase.80 81 82 83 84 85 
According to the commenter, this would affect the amount of Hg in the 
boundary and initial conditions. The commenters claim that EPA's 
modeling did not account for these emission changes, thus leading to an 
overestimate of U.S. EGU-attributable deposition in 2016.
---------------------------------------------------------------------------

    \80\ Jaffe D., Prestbo E., Swartzendruber P., Weiss-Penzias P., 
Kato S., Takami A., Hatakeyama S., Kajii Y., 2005. ``Export of 
Atmospheric Mercury From Asia,'' Atmospheric Environment, 39, 3029-
3038.
    \81\ Jaffe D., Strode S., 2008. ``Fate and Transport of 
Atmospheric Mercury From Asia,'' Environmental Chemistry, 5, 121.
    \82\ Pacyna E.G., Pacyna J.M., Sundseth K., Munthe J., Kindbom 
K., Wilson S., Steenhuisen F., Maxson P., 2010. ``Global Emission of 
Mercury to the Atmosphere From Anthropogenic Sources in 2005 and 
Projections to 2020,'' Atmospheric Environment, 44, 2487-2499.
    \83\ Pirrone N., Cinnirella S., Feng X., Finkelman R.B., Friedli 
H.R., Leaner J., Mason R., Mukherjee A.B., Stracher G.B., Streets D. 
G., Telmer K., 2010. ``Global Mercury Emissions to the Atmosphere 
From Anthropogenic and Natural Sources,'' Atmospheric Chemistry and 
Physics, 10, 5951-5964.
    \84\ Streets, D.G., Zhang, Q., Wu, Y., 2009. ``Projections of 
Global Mercury Emissions in 2050.'' Environmental Science & 
Technology 43, 2983-2988.
    \85\ Weiss-Penzias P., Jaffe D., Swartzendruber P., Dennison 
J.B., Chand D., Hafner W., Prestbo E., 2006. ``Observations of Asian 
Air Pollution in the Free Troposphere at Mt. Bachelor Observatory in 
the Spring of 2004,'' Journal of Geophysical Research, 110, D10304.
---------------------------------------------------------------------------

    Several commenters noted that Hg emissions from U.S. EGUs are small 
when compared to global Hg emissions totals and natural sources within 
the U.S. These commenters used a variety of information to support 
alternative conclusions about the necessity to control U.S. EGU 
emissions to reduce Hg risk: global Hg emissions inventories, global 
and regional photochemical modeling research, and observation-based 
assessments. A commenter stated that EPA has not acknowledged the 
dramatic decline in Hg emissions from U.S. EGUs since the late 1990s 
(approximately 50 percent) to the current level or consider the 
relative magnitude of Hg emissions from U.S. EGUs compared to other 
sources, natural (such as fires) and human-caused.
    Response: The EPA disagrees that boundary and initial conditions 
used in modeling Hg deposition need adjustment for several reasons. 
First, the EPA does not use the first 10 days of the modeling 
simulation in the analysis, which is more than sufficient to remove the 
influence of initial conditions on Hg deposition estimates.\86\ Second, 
it is difficult to accurately characterize the speciation of Hg that 
flows into the U.S. from other countries due to the lack of data near 
the boundaries of the modeling domain. Third, the boundary inflow for 
the CMAQ Hg modeling used in the Hg deposition modeling are based on a 
global model GEOS-CHEM simulation using a 2000 based global 
inventory.\87\ A recently published comparison of global Hg emissions 
by continent for 2000 and 2006 found that total Hg emissions from Asia 
(and Oceania) total 1,306 Mg/yr in 2000 and 1,317 Mg/yr in 2006.\88\ 
The EPA has determined that because the Asian Hg emissions estimated in 
this study are nearly constant between 2005 and 2006, any adjustments 
to the boundary conditions or adjustments to modeled Hg deposition 
would be invalid and inappropriate. Recent research has shown that 
ambient Hg concentrations have been decreasing in the northern 
hemisphere since 2000.\89\ Because emissions from Asia have not 
appreciably changed between 2000 and 2006 and ambient Hg concentrations 
have been decreasing, ENVIRON's analysis contains incorrect assumptions 
and we need not address them further. For these reasons and the large 
uncertainties surrounding projected Hg

[[Page 9339]]

global inventories, the EPA concludes that the most appropriate 
technical choice is to keep the Hg boundary conditions the same between 
the 2005 and 2016 simulations.
---------------------------------------------------------------------------

    \86\ Pongprueksa, P., Lin, C.J., Lindberg, SE., Jang, C., 
Braverman, T., Bullock, O.R., Ho, T.C., Chu, H.W., 2008. 
``Scientific Uncertainties in Atmospheric Mercury Models III: 
Boundary and Initial Conditions, Model Grid Resolution, and Hg (II) 
Reduction Mechanism.'' Atmospheric Environment 42, 1828-1845.
    \87\ Selin, NE., Jacob, D.J., Park, R.J., Yantosca, R.M., 
Strode, S., Jaegle, L., Jaffe, D. 2007. ``Chemical Cycling and 
Deposition of Atmospheric Mercury: Global Constraints From 
Observations.'' Journal of Geophysical Research-Atmospheres 112.
    \88\ Streets et al., 2009.
    \89\ Slemr, F., Brunke, E.G., Ebinghaus, R., Kuss, J., 2011. 
``Worldwide Trend of Atmospheric Mercury Since 1995.'' Atmospheric 
Chemistry and Physics 11, 4779-4787.
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    The EPA also disagrees with the commenters' assertion that EPA has 
not acknowledged the decline in Hg emissions for the U.S. EGUs since 
the late 1990s. The EPA analyzed historical, current, and future 
projected Hg emissions from the power generation sector, as cited in 
the preamble to the proposed rule. The EPA also disagrees with the 
commenters' assertions that EPA failed to consider the relative 
magnitude of Hg emissions from U.S. EGUs compared to other sources. As 
noted in the Hg Risk TSD, the EPA modeled Hg emissions from U.S. and 
non-U.S. anthropogenic and natural sources to estimate Hg deposition 
across the country. The EPA also determined the contribution of Hg 
emissions from U.S. EGUs to total Hg deposition in the U.S. by running 
modeling simulations for 2005 and 2016 with Hg emissions from U.S. EGUs 
set to zero. Based on the Hg Risk TSD, Hg emissions from U.S. EGUs pose 
a hazard to public health based on the total of 29 percent of modeled 
watersheds potentially at-risk. Our analyses show that of the 29 
percent of watersheds with population at-risk, in 10 percent of those 
watersheds U.S. EGU deposition alone leads to potential exposures that 
exceed the MeHg RfD, and in 24 percent of those watersheds, total 
potential exposures to MeHg exceed the RfD and U.S. EGUs contribute at 
least 5 percent to Hg deposition.
    The commenters suggest that Hg emissions from U.S. EGUs represent a 
limited portion of the total Hg emitted worldwide, including 
anthropogenic and natural sources. While EPA acknowledges that Hg 
emissions from U.S. EGUs are a small fraction of the total Hg emitted 
globally, it views the environmental significance of Hg emissions from 
U.S. EGUs and other domestic sources as a more germane consideration. 
Mercury is emitted from EGUs in three forms. Each form of Hg has 
specific physical and chemical properties that determine how far it 
travels in the atmosphere before depositing to the landscape. Although 
gaseous oxidized Hg and particle-bound Hg are generally local/regional 
Hg deposition concerns, all forms of Hg may deposit to local or 
regional watersheds. U.S. coal-fired power plants account for over half 
of the U.S. controllable emissions of the quickly depositing forms of 
Hg. Although emissions from international Hg sources contribute to Hg 
deposition in the U.S., the peer reviewed scientific literature shows 
that Hg emissions from U.S. EGUs in the U.S. significantly enhance Hg 
deposition and the response of ecosystems in the U.S. 
90 91 92 93
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    \90\ Caffrey et al., 2010.
    \91\ Driscoll, C. T., Han, Y.-J., Chen, C. Y., Evers, D. C., 
Lambert, K. F., Holsen, T. M., et al., (2007). ``Mercury 
Contamination in Forest and Freshwater Ecosystems in the 
Northeastern United States.'' BioScience, 57(1).
    \92\ Keeler, G.J., Landis, M.S., Norris, G.A., Christianson, 
E.M., Dvonch, J.T., 2006. ``Sources of Mercury Wet Deposition in 
Eastern Ohio, USA.'' Environmental Science & Technology 40, 5874-
5881.
    \93\ White, E.M., Keeler, G.J., Landis, M.S., 2009. ``Spatial 
Variability of Mercury Wet Deposition in Eastern Ohio: Summertime 
Meteorological Case Study Analysis of Local Source Influences.'' 
Environmental Science & Technology 43, 4946-4953.
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c. Hg Deposition Modeling
1. General Comments on Deposition Modeling
    Comment: Several commenters stated that according to the ENVIRON 
report, the EPA overestimated U.S. EGU-attributable Hg deposition by 10 
percent on average (and up to 41 percent in some areas). The commenters 
claim this overestimation is the result of boundary condition 
treatment, the exclusion of U.S. fire emissions,\94\ and Hg plume 
chemistry approach. In addition, one commenter referenced the same 
ENVIRON report and stated that before implementation of controls 
required by the proposed rule, areas with relatively high EGU-
attributable Hg deposition (one-fifth or more of total deposition) in 
2016 constitute less than 0.25 percent of the continental U.S. area, 
and only three grid cells have EGU contributions exceeding half of 
total deposition.
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    \94\ Finley, B.D., Swartzendruber, P.C., Jaffe, D.A., 2009. 
``Particulate Mercury Emissions in Regional Wildfire Plumes Observed 
at the Mount Bachelor Observatory.'' Atmospheric Environment 43, 
6074-6083.
---------------------------------------------------------------------------

    Another commenter suggested that current research shows that models 
of Hg atmospheric fate and transport overestimate the local and 
regional impacts of some anthropogenic sources, such as U.S. EGUs. 
Thus, according to the commenter, calculated contributions to Hg 
deposition and fish tissue MeHg levels from these sources represent 
upper bounds of actual contributions,\95\ \96\ and EPA should present 
results as estimates of lower and upper bound limits.
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    \95\ Seigneur, C., Lohman, K., Vijayaraghavan, K., Shia, R.L., 
2003. ``Contributions of global and regional sources to mercury 
deposition in New York State.'' Environmental Pollution 123, 365-
373.
    \96\ Seigneur, C., Vijayaraghavan, K., Lohman, K., 
Karamchandani, P., Scott, C., 2004. ``Modeling the atmospheric fate 
and transport of mercury over North America: power plant emission 
scenarios.'' Fuel Processing Technology 85, 441-450.
---------------------------------------------------------------------------

    Response: The EPA disagrees with the information presented by 
ENVIRON. The ENVIRON report is based on the misapplication of multiple 
incommensurate modeling studies and false premises which include the 
incorrect notion that the boundary conditions are over-estimated and 
the idea that EPA should use in-plume chemistry that has not been 
explicitly characterized and peer reviewed. Reactions that may reduce 
gas phase oxidized Hg in plumes have not been explicitly identified in 
literature. Recent studies in central Wisconsin and central California 
suggest the opposite may happen; elemental Hg may be oxidized to Hg(II) 
in plumes.\97\ \98\ Better field study measurements and specific 
reaction mechanisms need to be identified before making conclusions 
about potential Hg in-plume chemistry or applying surrogate reactions 
in regulatory modeling. The possibility that Hg(0) is oxidized to 
Hg(II) in plumes suggests coal-fired power plant Hg contribution inside 
the U.S. may be underestimated in EPA modeling.
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    \97\ Kolker, A., Olson, M.L., Krabbenhoft, D.P., Tate, M.T., 
Engle, M.A., 2010. ``Patterns of mercury dispersion from local and 
regional emission sources, rural Central Wisconsin, USA.'' 
Atmospheric Chemistry and Physics 10, 4467-4476.
    \98\ Rothenberg, SE., McKee, L., Gilbreath, A., Yee, D., Connor, 
M., Fu, X.W., 2010. ``Wet deposition of mercury within the vicinity 
of a cement plant before and during cement plant maintenance.'' 
Atmospheric Environment 44, 1255-1262.
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    The EPA asserts that the numbers suggested by the commenter are 
inaccurate, as it is not appropriate to adjust EPA's deposition 
estimates based on previous Hg modeling done with older Hg chemistry, 
in-plume reactions that have not been explicitly identified, and 
erroneous adjustments to Hg boundary inflow. Recent research has shown 
that ambient Hg concentrations have been decreasing in the northern 
hemisphere since 2000.\99\ The EPA declines to revise this analysis as 
commenter suggests for several reasons, including available evidence 
indicates that emissions from China have not appreciably changed 
between 2000 and 2006 \100\ and ambient Hg concentrations have 
decreased, the commenter inappropriately comingled out-of-date Hg 
modeling simulations with EPA results, and ENVIRON's analysis has not 
undergone any scientific peer review and presents information with 
incorrect assumptions as noted in this response.
---------------------------------------------------------------------------

    \99\ Slemr et al., 2011.
    \100\ Streets et al., 2009.
---------------------------------------------------------------------------

    The EPA also disagrees with the commenter's interpretation of the 
applicability of wildfire Hg emissions to

[[Page 9340]]

this assessment. Finley et al., (2009) \101\ suggests caution when 
using their field data to make assumptions about Hg(p) emissions from 
wildfires; the estimated particulate Hg emissions from wildfires is 
based on one field site with a limited sample size, and the assumptions 
made (such as the observed Hg(p) to carbon monoxide ratios at this 
location) may not be valid on a broader scale.\102\ Mercury emissions 
from wildfires are a re-volatilization of previously deposited Hg.\103\ 
Given that electrical generating power plants are currently and 
historically have been among the largest Hg-emitting sources, the 
inclusion of wildfire emissions in a modeling assessment would 
necessarily increase the contribution from this emissions sector.
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    \101\ Finley et al., 2009.
    \102\ Id.
    \103\ Wiedinmyer, C., Friedli, H., 2007. ``Mercury emission 
estimates from fires: An initial inventory for the United States.'' 
Environmental Science & Technology 41, 8092-8098.
    \104\ Seigneur et al., 2003.
    \105\ Seigneur et al., 2004.
---------------------------------------------------------------------------

    The EPA disagrees with the assertion that EPA failed to consider 
the relative magnitude of Hg emissions from U.S. EGUs compared to other 
sources and disagrees with the interpretation of EGU deposition 
presented in the ENVIRON report. As noted in the Hg Risk TSD, the EPA 
modeled Hg emissions from U.S. and non-U.S. anthropogenic and natural 
sources to estimate Hg deposition across the country. The EPA also 
determined the contribution of Hg emissions from U.S. EGUs to total Hg 
deposition in the U.S. by running modeling simulations for 2005 and 
2016 with Hg emissions from U.S. EGUs set to zero. Hg emissions from 
U.S. EGUs pose a hazard to public health based on the total of 29 
percent of modeled watersheds potentially at-risk. Our analyses show 
that of the 29 percent of watersheds with population at-risk, in 10 
percent of those watersheds U.S. EGU deposition alone leads to 
potential exposures that exceed the MeHg RfD, and in 24 percent of 
those watersheds, total potential exposures to MeHg exceed the RfD and 
U.S. EGUs contribute at least 5 percent to Hg deposition. The ENVIRON 
report provides no risk analysis of EGU contribution.
    The EPA disagrees that research 104 105 presented by the 
commenter shows that U.S. EGU impacts are over-estimated. The 
commenter's references do not support this statement. The references 
provided by the commenter are based on Hg modeling that uses models 
that are no longer applied and that are based on out-dated Hg chemistry 
and deposition assumptions. Given the advances in Hg modeling since the 
early 2000s, the EPA does not believe an upper and lower bound estimate 
is necessary.
2. Chemical Reactions
    Comment: Several commenters stated that the CMAQ modeling fails to 
account for the chemical reduction of gaseous ionic Hg to elemental Hg 
that may occur in EGU plumes. The commenters noted that EPA did not use 
the Electric Power Research Institute's (EPRI) Advanced Plume-in-Grid 
Treatment, which includes a surrogate reaction to reduce gaseous ionic 
Hg to elemental Hg inside plumes. Multiple commenters claimed that the 
reduction of reactive gaseous Hg to gaseous elemental Hg has been 
reported in power plant plumes and that supporting data include 
atmospheric concentrations of speciated Hg measured downwind of power 
plant stacks at ground-level monitor sites and dispersion model 
predictions.106 107 A detailed description of various plume 
measurement studies is provided in EPRI Comments, Section 3.4: Plant 
Bowen, Georgia, Plant Pleasant, Wisconsin, and Plant Crist, Florida. 
One commenter believed the impact of grid resolution (12 km sized grid 
cells) on the CMAQ modeling was not appropriately addressed by EPA. 
Their concerns due to grid resolution include the notion that a 
source's emissions will be averaged over the entire grid cell. 
According to the commenter, such averaging causes an artificially fast 
dilution that smoothes out areas of high and low deposition, which may 
limit the ability of the model to simulate smaller areas of localized 
high deposition. This commenter believed that using the APT would 
address these issues.
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    \106\ Edgerton, E.S., Hartsell, B.E., Jansen, J.J., 2006. 
``Mercury speciation in coal-fired power plant plumes observed at 
three surface sites in the southeastern U.S.'' Environmental Science 
& Technology 40, 4563-4570.
    \107\ Lohman, K., Seigneur, C., Edgerton, E., Jansen, J., 2006. 
``Modeling mercury in power plant plumes.'' Environmental Science & 
Technology 40, 3848-3854.
---------------------------------------------------------------------------

    Response: The EPA disagrees with the commenters' claims that 
oxidized Hg chemically reduces to elemental mercury within the plume. 
There is no evidence of these chemical reactions in the scientific 
literature. The references cited by the commenters are from non-peer 
reviewed reports and conference proceedings. The EPA does not consider 
information presented at conferences or industry reports to be peer 
reviewed literature, and consideration of oral presentation material 
would be inappropriate. Further, even these cited references do not 
provide sufficient information for incorporating the supposed reactions 
into the modeling (e.g., specific chemical reactions, reaction rates, 
etc.); rather, the cited references only suggest that oxidized gas 
phase Hg could be reduced and postulate a possible pathway.
    Recent studies in central Wisconsin and central California suggest 
the opposite may happen; elemental Hg may be oxidized to Hg(II) in 
plumes.108 109 Better field study measurements and specific 
reaction mechanisms need to be identified before making conclusions 
about potential Hg in-plume chemistry or applying surrogate reactions 
in regulatory modeling. Currently, models such as Advanced Plume 
Treatment (APT) use a surrogate reaction for the potential reactive gas 
phase Hg reduction that may or may not occur in plumes.\110\ Reactions 
that may reduce gas phase oxidized Hg in plumes have not been 
explicitly identified in literature. The application of potentially 
erroneous in-plume chemistry that is a fundamental component of APT 
would be inappropriate. In addition, the APT is not available in the 
most recent version of CMAQ. It would be inappropriate for EPA to apply 
an out of date photochemical model with in-plume chemistry that has not 
been shown to exist.
---------------------------------------------------------------------------

    \108\ Kolker et al., 2010.
    \109\ Rothenberg et al., 2010.
    \110\ Vijayaraghavan, K., Seigneur, C., Karamchandani, P., Chen, 
S.Y., 2007. ``Development and application of a multipollutant model 
for atmospheric mercury deposition.'' Journal of Applied Meteorology 
and Climatology 46, 1341-1353.
---------------------------------------------------------------------------

    The EPA agrees with the commenter that the CMAQ modeling with 12 km 
grid resolution may provide a lower bound estimate on EGU contribution 
as higher impacts using finer grid resolution are possible. The 
commenter's assertion that EGU impacts are likely higher further 
supports the final conclusions of the exposure modeling assessment. The 
EPA notes that the application of a photochemical model at a 12 km grid 
resolution for the entire continental U.S. is more robust in terms of 
grid resolution and scale that anything published in literature and 
represents the most advanced modeling platform used for a national Hg 
deposition assessment.
3. Modeled Deposition Compared to Measured Deposition
    Comment: Multiple commenters expressed dissatisfaction related to 
EPA's model performance evaluation of CMAQ estimated Hg deposition. The 
commenters stated that EPA failed to evaluate the CMAQ model against 
real-world measurements and that EPA fails to provide first-hand 
information on wet and dry deposition processes. The commenters also 
stated that EPA needs

[[Page 9341]]

to assess how predicted values of deposition compare to Mercury 
Deposition Network (MDN) data and how predicted values of ambient 
speciated Hg concentrations compare to measurement networks like AMNet 
and SEARCH. In addition, commenters stated that EPA used highly 
aggregated performance metrics comparing model estimates to 
observations that they believe result in a degraded and lenient 
operational evaluation of the modeling system. A commenter suggested 
that EPA's model performance provides no confidence for the intended 
purpose of estimating deposition near point sources. One commenter 
simply noted that EPA's model over-estimated total Hg wet deposition at 
MDN monitors. Finally, several commenters noted that EPA presented a 
negative modeled wet deposition total in the Air Quality Modeling TSD, 
which is physically impossible.
    Response: EPA agrees with the commenters that the negative estimate 
for wet deposition in the Air Quality Modeling TSD was an error. This 
error reflected an incorrect calculation in the post-processing of 
model and observation pairs that only influenced the calculation of 
model performance metrics. The error has been fixed, and the model 
performance metrics in the revised Air Quality Modeling TSD have been 
updated. This error did not affect Hg deposition. In response to 
comments, the EPA provided additional model performance evaluation by 
season to the revised Air Quality Modeling TSD. In addition, in 
response to comments, the EPA also included model performance 
evaluation for total Hg wet deposition for the 36 km modeling domain in 
the revised Air Quality Modeling TSD.
    The EPA disagrees that it did not conduct an assessment comparing 
CMAQ total Hg wet deposition estimates to MDN data. The Air Quality 
Modeling TSD clearly shows a comparison of CMAQ estimated total Hg wet 
deposition with MDN data for the entire length of the modeling period. 
The CMAQ wet deposition of Hg has been and will continue to be 
extensively evaluated against MDN sites.\111\ There is no dry 
deposition monitoring network, which precludes evaluating CMAQ dry 
deposition processes. The EPA disagrees that an evaluation of ambient 
speciated Hg against routine monitor networks such as AMNet or SEARCH 
would be useful for this particular modeling application. The AMNet Hg 
network did not exist in 2005, which is EPA's baseline model simulation 
time period, and the SEARCH network started making preliminary 
measurements of Hg at one or two sites in 2005. In addition, 
measurement artifacts related to gaseous oxidized Hg are difficult to 
quantify and make direct comparison to model estimates 
problematic.\112\ Considering the problems associated with TEKRAN 
measurements of ambient Hg and the sparse nature of routine 
measurements in the U.S., the EPA did not compare ambient Hg against 
model estimates.
---------------------------------------------------------------------------

    \111\ Bullock, O.R., Atkinson, D., Braverman, T., Civerolo, K., 
Dastoor, A., Davignon, D., Ku, J.Y., Lohman, K., Myers, T.C., Park, 
R.J., Seigneur, C., Selin, NE., Sistla, G., Vijayaraghavan, K., 
2009. ``An analysis of simulated wet deposition of mercury from the 
North American Mercury Model Intercomparison Study.'' Journal of 
Geophysical Research-Atmospheres 114.
    \112\ Lyman, S.N., Jaffe, D.A., Gustin, M.S., 2010. ``Release of 
mercury halides from KCl denuders in the presence of ozone.'' 
Atmospheric Chemistry and Physics 10, 8197-8204.
---------------------------------------------------------------------------

    The EPA disagrees that the model performance presented in the air 
quality TSD is insufficient. The EPA asserts that the model performance 
evaluation is generally similar to the level of model performance 
presented in literature. One commenter presented the results of several 
Hg modeling studies as providing information that the commenter 
believes to be relevant for this assessment in terms of model 
performance metric estimation and the level of model performance 
evaluation shown for assessments modeling Hg near point sources. For 
example, one cited study titled ``Modeling Mercury in Power Plant 
Plumes'' models near-source Hg chemistry from U.S. EGUs, but provides 
absolutely no information about model performance evaluation.\113\
---------------------------------------------------------------------------

    \113\ Lohman et al., 2006.
---------------------------------------------------------------------------

    Another commenter identified two studies as supposedly having Hg 
modeling results that are applicable to EPA's 
analysis.114 115 These studies present similar model 
performance metrics as EPA. The EPA disagrees that the Agency used 
``highly aggregated performance metrics'' that result in degraded and 
lenient model evaluation. The studies presented 116 117 as 
relevant for point source mercury modeling use an approach to aggregate 
the operational performance metrics across many monitor locations as 
did EPA; however, these articles calculate long term annual averages of 
modeled and observed total Hg wet deposition before estimating 
performance metrics. It is common practice to pair modeled estimates 
and observations in space and time (weekly in this case) and estimate 
performance metrics, then average all the metrics together. The latter 
is the approach taken by the EPA and should have been taken by the 
studies presented by the commenter. The EPA used a more stringent 
approach to match observations and predictions and aggregation of 
operational model performance. The EPA agrees that the commenter 
accurately restated total wet deposition model performance information 
provided by the EPA in the Air Quality Modeling TSD. To provide 
context, other Hg modeling studies show a positive bias for annual 
total Hg wet deposition.118 119 An annual Hg modeling 
application done by ENVIRON \120\ and the Atmospheric and Environmental 
Research for Lake Michigan Air Directors Consortium show seasonal 
average normalized bias between 70 and 158 percent and seasonal average 
normalized error between 72 and 503 percent.\121\ These results 
indicate a very large over-estimation tendency. The model performance 
shown by EPA is consistent with other long-term Hg modeling 
applications.
---------------------------------------------------------------------------

    \114\ Seigneur, C., Lohman, K., Vijayaraghavan, K., Jansen, J., 
Levin, L., 2006. ``Modeling atmospheric mercury deposition in the 
vicinity of power plants.'' Journal of the Air & Waste Management 
Association 56, 743-751.
    \115\ Vijayaraghavan, K., Karamchandani, P., Seigneur, C., 
Balmori, R., Chen, S.-Y., 2008. ``Plume-in-grid modeling of 
atmospheric mercury.'' Journal of Geophysical Research-Atmospheres 
113.
    \116\ Seigneur, C., Lohman, K., Vijayaraghavan, K., Jansen, J., 
Levin, L., 2006. ``Modeling atmospheric mercury deposition in the 
vicinity of power plants.'' Journal of the Air & Waste Management 
Association 56, 743-751.
    \117\ Vijayaraghavan, K., Karamchandani, P., Seigneur, C., 
Balmori, R., Chen, S.-Y., 2008. ``Plume-in-grid modeling of 
atmospheric mercury.'' Journal of Geophysical Research-Atmospheres 
113.
    \118\ Id.
    \119\ Vijayaraghavan et al., 2007.
    \120\ Yarwood, G, Lau, S., Jia, Y., Karamchandani, P., 
Vijayaraghavan, K. 2003. Final Report: Modeling Atmospheric Mercury 
Chemistry and Deposition with CAMx for a 2002 Annual Simulation. 
Prepared for Wisconsin Department of Natural Resources. http://www.gypsymoth.wi.gov/air/toxics/mercury/hg_X97579601_appB.pdf.
    \121\ Yarwood et al., 2003.
---------------------------------------------------------------------------

4. Excess Local Deposition From Hg Emissions From U.S. EGUs (Deposition 
Hotspots)
    Comment: One commenter stated that reducing Hg will benefit local 
environments. The commenter stated that a 2007 study confirmed the 
presence of Hg ``hotspots'' downwind from coal-fired power plants and 
confirmed that coal-fired power plants within the U.S. are the primary 
source of Hg to the Great Lakes and the Chesapeake Bay.\122\ The 
commenter also stated that the study is consistent with a major Hg 
deposition study conducted

[[Page 9342]]

by the EPA and the University of Michigan that concluded that 
approximately 70 percent of Hg wet deposition resulted from local 
fossil fuel emissions in the region.\123\
---------------------------------------------------------------------------

    \122\ Evers, David C. et al., 2007. ``Biological Mercury 
Hotspots in the Northeastern United States and Southeastern 
Canada,'' Bioscience. Vol. 57 No. 1. p. 29.
    \123\ Cohen, et al., 2004. ``Modeling the Atmospheric Transport 
and Deposition of Mercury to the Great Lakes,'' Environmental 
Research 95, (247-265).
---------------------------------------------------------------------------

    One commenter agreed with the Agency's assessment of the potential 
for deposition ``hotspots'' that shows that Hg deposition near EGUs can 
be three times as large as the regional average. The commenter stated 
that this excess Hg deposition would substantially increase the health 
and environmental risks associated with emissions at these sites. The 
same commenter also stated that EPA applied a conservative methodology 
to quantify near-source Hg deposition. The commenter stated that 
maximum excess local Hg deposition may be significantly underestimated 
by averaging high deposition sites downwind of an EGU in the direction 
of prevailing winds with lower excess deposition at locations close to 
but frequently upwind of the facility. The same commenter suggests that 
had EPA used CMAQ and individual 12x12 km\2\ grid cells to quantify 
local deposition, the model could increase the excess Hg deposition at 
these locations significantly and place them at even greater risk of 
adverse health and environmental effects of HAP from U.S. EGUs.
    One commenter stated that the Hubbard Brook Research Foundation 
issued a report in 2007 that identified five Hg hotspots, one of which 
was in the Adirondack Park, along with four suspected hotspots.\124\ 
The commenter stated that this study also provides a good description 
of the impacts of Hg on the Common Loon, which is a symbol of a healthy 
Adirondack environment.
---------------------------------------------------------------------------

    \124\ Driscoll, C.T., D. Evers, K.F. Lambert, N. Kamman, T. 
Holsen, Y-J. Han, C. Chen, W. Goodale, T. Butler, T. Clair, and R. 
Munson. Mercury Matters: Linking Mercury Science with Public Policy 
inthe Northeastern United States. 2007. Hubbard Brook Research 
Foundation. Science Links Publication. Vol. 1, no. 3.
---------------------------------------------------------------------------

    One commenter stated that there is there is no evidence of Hg 
hotspots due to local deposition associated with coal-fired power 
plants. According to the commenter, the EPA's use of a 50 km radius to 
calculate hotspots is flawed. The commenter stated that modeling 
studies show that deposition of Hg emitted from power plants is not 
confined to a 50-km radius around the plants and that most emissions 
from power plants travel beyond 50 km.\125\
---------------------------------------------------------------------------

    \125\ Seigneur et al., 2006.
---------------------------------------------------------------------------

    Several commenters stated that the EPA does not adequately define 
hotspots in this proposed rule. Those same commenters cited a previous 
EPA definition of hotspots as ``a waterbody that is a source of 
consumable fish with MeHg tissue concentrations, attributable solely to 
utilities, greater than EPA's MeHg water quality criterion of 0.3 mg/
kg'' (milligrams per kilogram).\126\ The same commenters stated that it 
is unclear why EPA changed from defining a hotspot by fish tissue MeHg 
concentration to defining a hotspot by depositional excess. Two 
commenters suggested that a Hg hotspot is a specific location that is 
characterized by elevated concentrations of Hg exceeding a well-
established criterion, such as a reference concentration (RfC) when 
compared to its surroundings. Those same commenters stated that 
identifying Hg hotspots should not be constrained to locations where 
concentrations can be attributed to a single source or sector.\127\ One 
of those two commenters noted that others have defined ``hotspots as a 
spatially large region in which environmental concentrations far exceed 
expected values, with such values (i.e. concentrations) being 2 to 
three standard deviations above the relevant mean.'' \128\
---------------------------------------------------------------------------

    \126\ U.S. EPA, 2005. 40 CFR Part 63 [OAR-2002-0056; FRL-7887-7] 
RIN 2060-AM96. Revision of December 2000 Regulatory Finding on the 
Emissions of Hazardous Air Pollutants From Electric Utility Steam 
Generating Units and the Removal of Coal- and Oil-Fired Electric 
Utility Steam Generating Units From the Section 112(c). Final rule, 
March 29.
    \127\ Evers et al., 2007.
    \128\ Sullivan T., 2005. ``The Impacts of Mercury Emissions from 
coal-fired Power Plants on Local Deposition and Human Health Risk.'' 
Presented at the Pennsylvania Mercury Rule Workgroup Meeting, 
October 28.
---------------------------------------------------------------------------

    One commenter stated that Hg concentrations are not always highest 
at sites closest to a major source. The commenter referred to a study 
\129\ that demonstrated that concentrations of atmospheric reactive 
gaseous Hg, gaseous elemental Hg, and fine particulate Hg were lower 
when measured 25 km from a 1,114 MW coal-fired EGU than when measured 
100 km away. The commenter stated that these findings contradict the 
idea, implicit in EPA's hotspot analysis, that reactive gaseous Hg 
decreases with distance from a large point source.
---------------------------------------------------------------------------

    \129\ Kolker, et al., 2010.
---------------------------------------------------------------------------

    One commenter provided information from a non-peer reviewed report 
with wet Hg deposition measurements downwind from the coal-fired power 
plant Crist in Pensacola, FL. The commenter stated that using the same 
data from these same wet deposition sites, one study \130\ found that 
Hg wet deposition and concentrations did not differ in a statistically 
significant manner among these three sites and that the concentrations 
values were similar to those from Mercury Deposition Network (MDN) 
sites that are more than 50 km away from Plant Crist located along the 
Northern Gulf of Mexico coast.
---------------------------------------------------------------------------

    \130\ Caffrey, J.M., Landing, W.M., Nolek, S.D., Gosnell, K.J., 
Bagui, S.S., Bagui, S.C., 2010. ``Atmospheric deposition of mercury 
and major ions to the Pensacola (Florida) watershed: spatial, 
seasonal, and inter-annual variability.'' Atmospheric Chemistry and 
Physics 10, 5425-5434.
---------------------------------------------------------------------------

    Another commenter stated that Plant Crist installed a wet scrubber 
and has operated that scrubber continuously since December 2009. The 
commenter stated that the scrubber reduces total Hg emissions by about 
70 percent and reduces emissions of reactive gaseous Hg by about 85 
percent. The commenter cited a non-peer reviewed conference 
presentation \131\ that reported changes in Hg wet deposition relative 
to historic measurements. The commenter stated that, taken 
collectively, these findings show that increased local total Hg 
deposition, possibly due to EGUs, and deposition changes due to changes 
in EGU emissions, are small.
---------------------------------------------------------------------------

    \131\ Krishnamurthy N., Landing W.M, Caffrey J.M., 2011. 
``Rainfall Deposition of Mercury and Other Trace Elements to the 
Northern Gulf of Mexico.'' Presented at the 10th International 
Conference on Mercury as a Global Pollutant, Halifax, Nova Scotia, 
Canada, July 27.
---------------------------------------------------------------------------

    Two commenters stated that a study by the Department of Energy 
(DOE) that collected and analyzed soil and vegetation samples for Hg 
near three U.S. coal-fired power plants--one in North Dakota, one in 
Illinois, and one in Texas--found no strong evidence of ``hotspots'' 
around these three plants.
    Two commenters stated that analysis of long-term trends in Hg 
emissions from coal-fired EGUs and wet deposition in Florida concluded 
that statistical analysis does not show evidence of a significant 
relationship between temporal trends in Hg emissions from coal-fired 
EGUs in Florida and Hg concentrations in precipitation during 1998 to 
2010.
    Two commenters stated that the Hg Risk TSD presents no information, 
summary statistics, and/or actual calculations showing how excess 
deposition within 50 km of an EGU source is obtained. The commenters 
stated that by assessing only Hg deposition attributable to EGUs, the 
EPA fails to provide a context for all other sources of Hg deposition. 
The commenters stated that the Agency does not explain why deposition 
from the top 10 percent of EGU Hg emitters does not decline, despite 
substantial reductions in modeled Hg emissions from those sources 
between 2005 and 2016.

[[Page 9343]]

According to the commenters this implies that the top 10 percent EGUs 
may have approximately as much of a regional effect as a local effect.
    Two commenters stated that the CMAQ model has limitations when used 
to predict local deposition and tends to overestimate local deposition. 
The commenters stated that modeling studies using either a plume model 
or an Eulerian model predict that 91 to 96 percent of the Hg emitted by 
an EGU travels beyond 50 km.\132\
---------------------------------------------------------------------------

    \132\ Edgerton et al., 2006.
---------------------------------------------------------------------------

    Response: The EPA agrees with the commenters that stated that Hg 
emissions from EGUs deposit locally and regionally and contribute to 
excess local deposition near U.S. EGUs. The EPA acknowledges additional 
studies \133\ cited by those commenters that corroborate EPA's 
conclusions. However, the EPA disagrees with those commenters' 
characterization of the methodology used to calculate the potential for 
excess local deposition. In response, the EPA has clarified the 
methodology in the new TSD entitled ``Technical Support Document: 
Potential for Excess Local Deposition of U.S. EGU Attributable Mercury 
in Areas near U.S. EGUs,'' which is available in the docket.
---------------------------------------------------------------------------

    \133\ Driscoll et al., 2007.
---------------------------------------------------------------------------

    The EPA agrees that there is no generally agreed-upon definition of 
``hotspot.'' As discussed in the preamble and TSD, for the purposes of 
the appropriate and necessary finding, the EPA determined that 
information on the potential for excess deposition of Hg in areas 
surrounding power plants would be useful in informing the finding. The 
EPA disagrees with some commenters who misinterpreted the intent of the 
Hg deposition hotspot analysis. Specifically, the analysis is not of 
``Hg hotspots'', which are often defined as high Hg concentration in 
fish, but rather of Hg deposition hotspots, defined as excess local Hg 
deposition around U.S. EGUs, as clarified in the new Local Deposition 
TSD. Because EPA did not identify ``Hg hotspots'' of high Hg 
concentrations in fish, the EPA's MeHg water quality criterion of 0.3 
mg/kg is irrelevant to EPA's analysis of excess local Hg deposition for 
this rule.
    The EPA disagrees that the analysis assumes that deposition of Hg 
is confined to a 50-km radius around power plants. The purpose of the 
EPA's analysis was to evaluate whether there existed ``excess 
deposition of Hg in nearby locations within 50 km of EGUs that might 
result in Hg deposition `hotspots'.'' As explained further in the new 
TSD, the EPA calculated the average EGU-attributable deposition (based 
on CMAQ modeling of Hg deposition) in the area 500 km around each plant 
and the average EGU-attributable deposition in the area 50 km around 
each plant. The difference between those two values is the excess local 
deposition around the plant. The EPA does not suggest Hg emissions from 
power plants stop at 50 km from the source. Some portion of EGU 
emissions deposit before 50 km, and some portion travels beyond 50 km. 
In addition, Hg disperses as it transports, so the average EGU 
contribution can be lower in areas beyond 50km relative to areas within 
50km even though Hg emissions from EGUs are depositing into U.S. 
watersheds.
    The EPA disagrees with some commenters' interpretation of the 
analysis as being focused on local deposition from all sources. In 
fact, the focus was on excess local deposition, rather than all local 
deposition. The EPA has clarified the purpose of the excess local 
deposition analysis in the new TSD. The EPA agrees that all EGUs add to 
local deposition, however, not all EGUs have local deposition that 
greatly exceeds regional deposition, which is the relevant question. 
The EPA disagrees that the DOE study referenced by the commenters 
attempted to assess the same analytical question as EPA's analysis. The 
DOE study focused on comparisons of total deposition near and far from 
power plants. The EPA's analysis did not focus on total Hg deposition, 
because as EPA acknowledges throughout its analysis, global sources of 
Hg deposition account for a large percentage of total Hg deposition. In 
addition, including global sources of Hg deposition would obscure the 
comparison of local and regional U.S. EGU-attributable Hg deposition. 
Because of regional deposition from both domestic and global sources of 
Hg, total Hg deposition at any location is unlikely to be highly 
correlated with local sources. The EPA's analysis focused on U.S. EGU-
attributable Hg deposition and demonstrates that for some plants 
(especially those with high Hg emissions), there is local deposition of 
Hg that exceeds the average regional deposition around the plant.
    The EPA's analysis shows heterogeneity in the amount of excess 
local deposition around plants. The new Local Deposition TSD shows that 
some plants can have local deposition that is less than the regional 
average deposition, suggesting that most of the Hg from those plants is 
transported regionally or that other EGUs in the vicinity of those 
plants dominate the deposition of Hg near the plants. This does not 
detract from the overall finding that around some power plants with 
high levels of Hg emissions excess local deposition is on average three 
times the regional EGU-attributable deposition around those plants.
    The EPA disagrees that the Hg Risk TSD did not provide sufficient 
information regarding the excess local deposition calculation. 
Nonetheless, the EPA has further clarified the methodology in the new 
Local Deposition TSD, including further descriptions of the method used 
to calculate the local and regional deposition around power plants 
along with maps and tables of results.
    The EPA disagrees with the commenters that stated that the 
discussion of local deposition in the Hg Risk TSD did not demonstrate 
that Hg deposition from the top 10 percent of EGU Hg emitters declines. 
Table 1 of the new Local Deposition TSD clearly shows that mean local 
deposition (within 50km of a plant) for the top 10 percent of emitters 
declines from 4.89 micrograms per cubic meter ([micro]g/m\3\) to 1.18 
[micro]g/m\3\. What does not change is the percent local excess for 
EGU-attributable Hg deposition. This implies that while Hg deposition 
from EGUs is declining, there is still an excess contribution to local 
deposition relative to regional deposition; e.g., because of 
dispersion, the contribution to average deposition outside 50 km from 
the plant is lower than the contribution to average deposition within 
50 km of the plant.
    The EPA disagrees that the information \134\ provided by the 
commenter regarding the Crist plant and other coal-fired power plants 
in Florida is relevant to EPA's analysis of excess local deposition 
from U.S. EGUs because it is based on measurements of wet Hg deposition 
without consideration of dry Hg deposition, which can be a significant 
component of Hg deposition.
---------------------------------------------------------------------------

    \134\ EPRI, 2010.
---------------------------------------------------------------------------

    The EPA disagrees with the commenter regarding the interpretation 
of the literature related to the spatial extent of deposition of Hg 
emitted by U.S. EGUs. The EPA also disagrees that the peer-reviewed 
CMAQ model has limitations for this application or overestimates local 
deposition. The commenter does not provide any credible support for the 
assertion that grid-based models typically overestimate local 
deposition surrounding EGUs. The EPA maintains that the CMAQ 
photochemical model represents the best science currently available in 
simulating atmospheric

[[Page 9344]]

chemistry, transport, and deposition processes.
    The study \135\ cited by the commenter to support the notion that 
91 to 96 percent of Hg emitted from power plants travels beyond 50 km 
is based on a photochemical transport model (the TEAM model) that does 
not employ current state-of-the-science and is not actively developed 
or updated. Furthermore, the modeling is based on grid cells that are 
20 km in size, which limits generalizability to EPA modeling performed 
at 12 km grid resolution using a state of the science photochemical 
grid model. The cited modeling study ignores dry deposition of 
elemental Hg from all sources, an assumption that clearly limits the 
regional impacts from sources.\136\ The methodology of this study cited 
by the commenter is critically flawed in that it presents no results 
where individual Hg emission sources are removed and the difference 
between the zero out simulation (where emissions from U.S. EGUs are set 
to zero) and the baseline model simulations are directly compared. 
Finally, the modeling study cited by the commenter presents an 
illustration of gridded total annual Hg deposition from the TEAM model 
for the eastern U.S. that clearly shows elevated annual total Hg 
deposition in the vicinity of coal-fired power plants in the Ohio River 
Valley and northeast Texas.
---------------------------------------------------------------------------

    \135\ Seigneur et al., 2006.
    \136\ Id.
---------------------------------------------------------------------------

d. Hg Risk TSD
1. Assumption of Linear Proportionality in Relationship Between Changes 
in Hg Deposition and Changes in Fish Tissue Hg Concentrations (Mercury 
Maps)
    Comment: Several commenters criticized EPA's assumption that 
changes in deposition resulting from U.S. EGU emissions of Hg will 
result in proportional changes in fish tissue Hg concentrations at the 
watershed level, as supported by the Mercury Maps modeling exercise. 
According to one commenter, the Mercury Maps model has limited 
capability to adequately determine bioaccumulation in fish. The same 
commenter stated that the Mercury Cycling Model (MCM) developed by EPRI 
is a more rigorous model that was developed expressly to evaluate the 
relationship between changes in atmospheric Hg deposition to 
waterbodies and changes in fish tissue MeHg levels.
    Several commenters stated that the Mercury Maps model has many 
deficiencies. Those commenters stated that Mercury Maps is a static 
model unable to account for the dynamics of ecosystems that affect Hg 
bioaccumulation in fish, cannot consider non-air Hg inputs to 
watersheds, and assumes reductions in airborne Hg lead to proportional 
reductions in fish MeHg concentrations. Another commenter claimed that 
data that demonstrate a steady-state linear reduction in fish tissue 
MeHg in response to a reduction in atmospheric Hg deposition within 
watersheds do not exist and provided several references that they 
claimed show non-linear responses to changes in Hg 
deposition.137 138
---------------------------------------------------------------------------

    \137\ Harris., R.C., John W.M. Rudd, Marc Amyot, Christopher L. 
Babiarz, Ken G. Beaty, Paul J. Blanchfield, R.A. Bodaly, Brian A. 
Branfireun, Cynthia C. Gilmour, Jennifer A. Graydon, Andrew Heyes, 
Holger Hintelmann, James P. Hurley, Carol A. Kelly, David P. 
Krabbenhoft, Steve E. Lindberg, Robert P. Mason, Michael J. 
Paterson, Cheryl L. Podemski, Art Robinson, Ken A. Sandilands, 
George R. Southworth, Vincent L. St. Louis, and Michael T. TateRudd, 
J. W.M., Amyot M., et al., Whole-Ecosystem study Shows Rapid Fish-
Mercury Response to Changes in Mercury Deposition. Proceedings of 
the National Academy of Sciences Early Edition, PNAS 2007 104 (42) 
pp. 16586-16591; (published ahead of print September 27, 2007).
    \138\ Orihel D.M., Paterson M.J., Blanchfield P.J., Bodaly R.A., 
Gilmour C.C., Hintelmann H., 2007. ``Temporal Changes in the 
Distribution, Methylation, and Bioaccumulation of Newly Deposited 
Mercury in an Aquatic Ecosystem,'' Environmental Pollution, 154, 77-
88.
---------------------------------------------------------------------------

    The same commenter disagreed with EPA's interpretation of Figure 2-
17 in the March TSD and stated that a U.S. Geological Survey national 
waterway study \139\ showed that sheet flow and drainage, not 
deposition, dominated input to the waterbodies it surveyed. The 
commenter stated that sheet flow and drainage could contain Hg and thus 
complicate the relationship that EPA asserts is linear and direct. 
Another commenter cited Figure 2-17 in the Hg Risk TSD as showing that 
there is no well-defined relationship between Hg deposition and MeHg 
concentrations in fish tissue on a national basis.
---------------------------------------------------------------------------

    \139\ Scudder B.C., Chasar L.C., Wentz D.A., Bauch N.J., Brigham 
M.E., Moran P.W., Krabbenhoft D.P., 2009. Mercury in fish, bed 
sediment, and water from streams across the United States, 1998-
2005: U.S. Geological Survey Scientific Investigations Report 2009-
5109, 74 p.
---------------------------------------------------------------------------

    Several commenters provided comments related to the assumption that 
fish tissue Hg levels used in the analysis represent a steady-state. 
One commenter stated that given the demonstrated lag time in response 
to deposition change, it is logical to conclude that a lag time needs 
to be incorporated in Mercury Maps to adjust the estimation of how much 
fish tissue MeHg levels decrease in response to decreases in Hg 
deposition attributable to U.S. EGUs. According to the same commenter, 
the METAALICUS study shows that there is a lag time (and a non-
proportional response) after 3-4 years. The same commenter noted that 
there are numerous factors that influence lag time including (1) 
watershed characteristics,\140\ (2) the fact that watersheds may act as 
legacy sources releasing Hg when disturbed,\141\ (3) the magnitude of 
emission reductions and subsequent changes in atmospheric deposition 
need to be weighed against the amount of Hg already in an 
ecosystem,\142\ (4) the distance of an ecosystem from Hg sources,\143\ 
and (5) the fact that Hg deposited to aquatic ecosystems becomes less 
available for uptake by biota over time.\144\ Another commenter stated 
that additional Mercury Maps assumptions do not allow for 
considerations of lag in response to changes in: (1) Deposition, (2) 
legacy sources of Hg such as mining, (3) historical Hg deposition, (4) 
natural Hg levels in fish, (5) ecosystem dynamics over time, or (6) the 
relative source contributions over time. Another commenter stated that 
lag times need to be included in the modeling and be able to vary from 
watershed to watershed and sometimes even from waterbody to waterbody 
within a watershed. Several commenters stated that the emission rates 
of Hg due to U.S. sources have been decreasing for more than a decade, 
while emissions due to sources outside the U.S. have been increasing. 
For this reason, the commenter asserted that the system is not at 
steady-state, a basic premise of the model. Another commenter stated 
that while the time lag for deposition to reach a waterbody is 
mentioned in the Hg Risk TSD, there is no discussion of the fact that a

[[Page 9345]]

portion of the deposition is unlikely to reach the water at all.
---------------------------------------------------------------------------

    \140\ Grigal D.F., 2002. ``Inputs and Outputs of Mercury from 
Terrestrial Watersheds: A Review,'' Environmental Review, 10, 1-39.
    \141\ Yang H., Rose N.L., Battarbee R.W., Boyle J.F., 2002. 
``Mercury and Lead Budgets for Lochnagar, a Scottish Mountain Lake 
and Its Catchment,'' Environmental Science & Technology, 36, 1383-
1388.
    \142\ Krabbenhoft D.P., Engstrom D., Gilmour C., Harris R., 
Hurley J., Mason R., 2007. Monitoring and Evaluating Trends in 
Sediment and Water Indicators. In Harris R., Krabbenhoft D., Mason 
R., Murray M.W., Reash R., Saltman T. (Eds.), Ecosystem Responses to 
Mercury Contamination: Indicators of Change. New York: Society of 
Environmental Toxicology and Chemistry (SETAC) North America 
Workshop on Mercury Monitoring and Assessment, CRC, pp. 47-87.
    \143\ Lindberg S. et al. 2007. ``A synthesis of progress and 
uncertainties in attributing the sources of mercury in deposition.'' 
Ambio 36(1): 19-32.
    \144\ Orihel D.M., Paterson M.J., Blanchfield P.J., Bodaly R.A., 
Hintelmann H., 2008. ``Experimental Evidence of a Linear 
Relationship between Inorganic Mercury Loading and Methylmercury 
Accumulation by Aquatic Biota,'' Environmental Science & Technology, 
41, 4952-4958.
---------------------------------------------------------------------------

    One commenter believes EPA incorrectly implied that its EGU risk 
estimates using Mercury Maps are underestimated because they do not 
account for legacy EGU-attributable deposition, which EPA assumes to be 
higher.
    One commenter stated that while EPA properly screened out 
watersheds with significant current non-air sources of Hg, the EPA did 
not adequately screen out watersheds with significant Hg contributions 
from non-air sources, specifically watersheds with historic Hg or gold 
mining or other industrial Hg discharges. The same commenter stated 
that EPA's study was not geographically balanced and was dominated by 
rivers in the coastal region of the southeast that has numerous 
wetlands, which are favorable locations for methylation and have 
conditions that are not typical of much of the rest of the U.S.
    Response: The EPA disagrees with the commenters who challenged the 
assumption of a linear proportional relationship between changes in 
U.S. EGU deposition and fish tissue Hg levels. The EPA specifically 
asked the SAB to evaluate EPA's assumption of linear proportionality in 
the relationship between Hg deposition and fish tissue MeHg 
concentrations, supported by the Mercury Maps analysis. The SAB peer 
review committee provided the following overall response, which 
generally supports EPA's approach:

    The SAB agrees with the Mercury Maps approach used in the 
analysis and has cited additional work that supports a linear 
relationship between mercury loading and accumulation in aquatic 
biota. These studies suggest that mercury deposited directly to 
aquatic ecosystems can become quickly available to biota and 
accumulated in fish, and reductions in atmospheric mercury 
deposition should lead to decreases in methylmercury concentrations 
in biota. The SAB notes other modeling tools are available to link 
deposition to fish concentrations, but does not consider them to be 
superior for this analysis or recommend their use. The integration 
of Community Multiscale Air Quality Modeling System (CMAQ) 
deposition modeling to produce estimates of changes in fish tissue 
concentrations is considered to be sound. Although the SAB is 
generally satisfied with the presentation of uncertainties and 
limitations associated with the application of the Mercury Maps 
approach in qualitative terms, it recommends that the document 
include quantitative estimates of uncertainty available in the 
existing literature.\145\
---------------------------------------------------------------------------

    \145\ U.S. EPA-SAB, 2011.

    The SAB peer review committee specifically addressed the MCM 
---------------------------------------------------------------------------
suggested by the commenter and had the following response:

    The SAB agrees with the application of Mercury Maps in this 
assessment. There are other modeling tools capable of making a 
national scale assessment, such as the Regional Mercury Cycling 
Model (R-MCM). However, the R-MCM is more data intensive and the 
results produced by the two model approaches should be equivalent.
    The R-MCM, a steady-state version of the time-dependent Dynamic 
Mercury Cycling Model, has been publicly available to and used by 
the EPA (Region 4, Athens, Environmental Research Laboratory) for a 
number of years. R-MCM requires more detail on water chemistry, 
methylation potential, etc., and yields more information as well. 
Substantial data support the Mercury Maps and the R-MCM steady-state 
results, so that the results of the sensitivity analysis and the 
outcomes from using the alternative models would be equivalent 
between the two modeling approaches. Though running an alternative 
model framework may provide additional reassurance that the Mercury 
Maps ``base case'' approach is a valid one, it is unlikely that 
substantial additional insight would be gained with the alternative 
model framework.\146\
---------------------------------------------------------------------------

    \146\ U.S. EPA-SAB, 2011.

    In addition, the SAB stated, ``Since the Mercury Maps approach was 
developed, several recent publications have supported the finding of a 
linear relationship between mercury loading and accumulation in aquatic 
biota.147 148 149 These studies suggested that mercury 
deposited directly to aquatic ecosystems can become quickly available 
to biota and accumulated in fish, and that reductions in atmospheric 
mercury deposition should lead to decreases in methylmercury 
concentrations in biota. These results substantiate EPA's assumption 
that proportionality between air deposition changes and fish tissue 
methylmercury level changes is sufficiently robust for its application 
in this risk assessment.'' \150\
---------------------------------------------------------------------------

    \147\ Orihel et al., 2007.
    \148\ Orihel et al., 2008.
    \149\ Harris et al., 2007.
    \150\ U.S. EPA-SAB, 2011.
---------------------------------------------------------------------------

    Based on the responses of the SAB peer review committee, the EPA's 
use of the linear proportionality assumption, supported by the Mercury 
Maps analysis, is well-supported.
    The EPA also disagrees with commenters' interpretation of Figure 2-
17. As stated in the Hg Risk TSD, while this figure is useful to 
demonstrate the lack of correlation across watersheds between total 
deposition of Hg and MeHg concentrations in fish tissue, it is not 
indicative of the likely correlation between changes in Hg deposition 
at a given watershed and changes in MeHg concentrations in fish tissue 
from that watershed. The SAB agreed with this interpretation, noting 
the importance of Figure 2-17 demonstrating that ``spatial variability 
of deposition rates is only one major driver of spatial variability of 
fish methylmercury and that variability of ecosystem factors that 
control methylation potential (especially wetlands, aqueous organic 
carbon, pH, and sulfate) also play a key role.'' \151\
---------------------------------------------------------------------------

    \151\ U.S. EPA-SAB, 2011.
---------------------------------------------------------------------------

    In response to recommendations from the SAB, the EPA expanded the 
discussion of uncertainties associated with the linearity assumption, 
including uncertainties related to the potential for sampled fish 
tissue Hg level to reflect previous Hg deposition and the potential for 
non-air sources of Hg to contribute to sampled fish tissue Hg levels. 
Each of these sources of uncertainty may result in potential bias in 
the estimate of exposure associated with current deposition. The EPA 
took steps to minimize the potential for these biases by (1) only using 
fish tissue Hg samples from after 1999, and (2) screening out 
watersheds that either contained active gold mines or had other 
substantial non-U.S. EGU anthropogenic emissions of Hg. The SAB 
commented that EPA's approach to minimizing the potential for these 
biases to affect the results of the risk analysis appears to be sound 
and that additional criteria that could be applied are unlikely to 
substantially change the results. As a result, the EPA disagrees with 
the commenter that EPA's screening process is inadequate. In addition, 
we conducted several sensitivity analyses to gauge the impact of 
excluding watersheds with the potential for non-EGU Hg emissions, and 
found that the results were robust to these exclusions.
    In response to specific comments regarding the use of the Mercury 
Maps model, the EPA clarifies that the Hg Risk TSD did not directly use 
the Mercury Maps model. Instead, the EPA applied an assumption of 
linear proportionality between changes in Hg deposition and changes in 
MeHg concentrations in fish that is supported by the Mercury Maps 
modeling. By assuming steady-state conditions in apportioning fish 
tissue Hg levels and risk, the EPA does not attempt to project lag 
times. Recent research cited by the SAB 152 153 154 
identifies relatively rapid response of fish tissue Hg to changes in Hg 
loading, which suggests that fish tissue Hg levels could react more

[[Page 9346]]

quickly to reductions in Hg deposition than previously thought. This 
finding reduces concern that fish tissue Hg levels could be linked to 
older patterns of Hg deposition and strengthens the approach used in 
the revised Hg Risk TSD. While fish tissue may respond rapidly to 
changes in Hg loading, this does not change the fact that previously 
emitted Hg from U.S. EGUs can be re-emitted and re-deposited, and thus 
affect Hg concentration in fish.
---------------------------------------------------------------------------

    \152\ Orihel et al., 2007.
    \153\ Orihel et al., 2008.
    \154\ Orihel et al., 2007.
---------------------------------------------------------------------------

2. Characterization of Subsistence Fishing Populations and Exposure 
Scenario
    Comment: Several commenters stated that EPA provides no clear 
definition of subsistence, near subsistence, or high-end fish 
consumption, instead assuming that poverty is a direct indication of 
subsistence fishing and high-end fish consumption. One commenter stated 
no documentation exists to supports these assumptions. Another 
commenter stated that EPA's definitions of subsistence fishers in the 
Hg Risk TSD are not consistent with earlier EPA documents and are used 
inconsistently throughout the Hg Risk TSD. Several commenters stated 
that while subsistence fishing can be associated with poverty, poverty 
does not indicate subsistence fishing. One commenter stated that by 
including watersheds with as few as 25 members of individuals living in 
poverty, the EPA overstates risks.
    One commenter stated that it is unclear what literature the Agency 
says ``generally supports the plausibility of high-end subsistence-like 
fishing * * * to some extent across the watersheds'' and stated that if 
other studies exist, the EPA should provide the values for comparison.
    One commenter stated that EPA combined two parameters with 
differing scales to establish the geographic unit used in the Hg Risk 
TSD risk assessment. The HUC watersheds are based on average about 35 
square miles in size, while U.S. census tracts used to identify 
watersheds relevant for subpopulations of interest--cover a few tenths 
to hundreds of square miles. Several commenters stated that it is 
unclear how the analysis handled differences in geographic resolution 
between watersheds and census tracts were.
    One commenter stated that the procedure for assigning census tracts 
could bias exposure outcomes. For example, the commenter stated that a 
single influential census tract in a watershed could drive risk, even 
if the watershed had only a minimal number of fish samples. The 
commenter stated that this possibility is a concern in urban areas, 
which account for the majority of census tracts, because these census 
tracts are more likely to be included in a risk analysis because they 
have more than 25 people living in poverty. The commenter stated that 
these census tracts may drive the extremes of the distribution without 
regard to the actual number of high-level, self-caught fish consumers 
within their boundaries. The commenter stated that they could not 
assess the potential bias and noted that EPA did not test the bias by 
sensitivity analyses.
    Several commenters stated that EPA was not clear whether the 
poverty criteria were applied in all scenarios or just for the high-end 
female fish consumer scenario. One commenter stated that EPA should 
apply the minimum 25 source population criteria only to populations of 
women of childbearing age. One commenter stated that EPA's assumption 
would result in any densely populated urban census tract with a single 
fish tissue sample being assigned to a modeled watershed with 
populations potentially at-risk, regardless of the actual degree of 
recreational or subsistence fishing taking place there.
    Response: The EPA agrees with the comments that subsistence fish 
consumption was not clearly defined, and we have provided a clearer 
definition in the revised Hg Risk TSD, however, this clarification does 
not result in any changes to the quantitative analysis. In the revised 
Hg Risk TSD, the EPA clarifies that ``subsistence fishers'' are defined 
as individuals who rely on noncommercial fish as a major source of 
protein.\155\ This definition is reflected in the range of fish 
consumption rates used in estimating risk. The likely presence of this 
type of subsistence fish consumer is supported by available peer 
reviewed literature (see Table 1-5 of the revised Hg Risk TSD). These 
studies clearly show that a subset of surveyed fishers consumes self-
caught fish at the rates cited in the Hg Risk TSD. The SAB peer review 
concluded that the consumption rates and locations for fishing activity 
are supported by the data presented in the Hg Risk TSD, and are 
generally reasonable and appropriate given the available data.\156\
---------------------------------------------------------------------------

    \155\ U.S. EPA, U.S. Environmental Protection Agency. 2000. 
Guidance for Assessing Chemical Contaminant Data for Use in Fish 
Advisories, Volume 3: Overview of Risk Management. Office of Science 
and Technology, Office of Water, U.S. Environmental Protection 
Agency, Washington, DC EPA 823-B-00-007.
    \156\ U.S. EPA-SAB, 2011.
---------------------------------------------------------------------------

    The EPA notes that there is some confusion in the comments related 
to the size of the watersheds modeled. Several commenters stated that 
HUC watersheds are 35 km on a side. The commenters appear to be 
referring to HUC8 classifications. The HUCs are defined for varying 
spatial resolutions. The geographic unit used as the basis for 
generating risk estimates is HUC12, which are watersheds about 10 km on 
a side, which is comparable with the size of the 12 km\2\ grid cells in 
CMAQ, which are 12 km\2\. The EPA has also clarified that the specific 
unit of analysis for this assessment is at the watershed, not 
enumerated subpopulations.
    The EPA only used the U.S. Census tracts to determine whether there 
are populations in the vicinity of a given watershed, which could 
increase the potential for a category of subsistence fishers to be 
active at that watershed. In the revised Hg Risk TSD, the EPA modified 
the female subsistence scenario to apply equally to all watersheds with 
fish tissue Hg data based on the likelihood that these populations have 
the potential to fish at most watersheds. As described in the revised 
Hg Risk TSD, the EPA made this change in response to SAB's concerns 
regarding the potential exclusion of watersheds with fewer than 25 
individuals and regarding coverage for high-end recreational fish 
consumption.\157\ Thus, concerns regarding the use of census data to 
select watersheds with the potential for subsistence fishing no longer 
apply to this scenario. However, for the remaining subsistence 
scenarios, the EPA continues to use U.S. Census tract-level data to 
evaluate the presence of a ``source population'' in the vicinity of the 
watershed being modeled for risk. In this context, the EPA uses the 
U.S. Census data to assess whether a socioeconomic status (SES)-
differentiated group similar to the particular type of subsistence 
fisher being modeled (e.g., poor Hispanics) are located in the vicinity 
of the watershed. If a source population is nearby, then this increases 
the potential that subsistence fishing activity could occur for that 
population scenario.
---------------------------------------------------------------------------

    \157\ This change led to a very small increase in the number of 
watersheds with populations potentially at-risk. In the Hg Risk TSD 
accompanying the proposed rule, approximately 4 percent of modeled 
watersheds were excluded based on the SES-based filtering criteria.
---------------------------------------------------------------------------

    The EPA continues to model risk for white and black subsistence 
fishers active in the southeast and for Hispanics assessed nationally. 
In this case, the EPA links poverty with subsistence fishing, as EPA 
only modeled locations with poor source populations. However, in 
modeling these three populations, the

[[Page 9347]]

EPA asserts that the presence of a poor source population indicates the 
potential for subsistence fishing activity, rather the presence of such 
activity. The linkage between poverty and higher rates of subsistence 
fish consumption is supported by the Burger et al. study,\158\ which 
identified substantially higher consumption rates for poor individuals 
(see Table 5 of the study). The EPA acknowledges that subsistence 
fishing activity by specific subpopulations might only be present 
across a subset of the watersheds EPA modeled for risk. However, given 
the stated goal of the analysis to determine the percent of watersheds 
where the potential exists for exposures to U.S. EGU-attributable Hg to 
represent a public health hazard, identifying a set of watersheds with 
the potential for the type of high fish consumption that leads to high 
Hg exposure is appropriate. The EPA notes that relatively few 
watersheds (less than 4 percent) have fish tissue Hg data, and, thus, 
can be included in the risk assessment. Consequently, while there is 
the potential for including some watersheds in the analysis that may 
not have currently active subsistence fishing activity, it is likely 
that EPA excluded other watersheds from the analysis where this type of 
subsistence fishing activity occurs due to a lack of fish tissue Hg 
data.
---------------------------------------------------------------------------

    \158\ Burger, J., 2002. ``Daily Consumption of Wild Fish and 
Game: Exposures of High End Recreationists,'' International Journal 
of Environmental Research and Public Health, 12 (4), 343-54.
---------------------------------------------------------------------------

    While EPA agrees with the comment that it is likely that exposure 
to total MeHg through commercial fish consumption represents a more 
significant risk for the general population than consumption of 
freshwater fish obtained through self-caught fishing activity, exposure 
to total MeHg through self-caught fish consumption is the most 
significant risk for subsistence fishing populations and high-end 
recreational fishers. For the subset of these populations that focus 
their fishing activity in freshwater streams and lakes, it is also the 
case that they will experience a higher fraction of MeHg exposure 
attributable to U.S. EGU Hg emissions. As a result, the EPA focused the 
risk assessment on subsistence fishers active at inland freshwater 
watersheds because they are likely to experience the highest levels of 
individual risk as a result of exposure to U.S. EGU-attributable Hg.
3. Cooking Loss Adjustment Factor
    Comment: Several commenters stated that EPA did not justify the 
selection of a cooking loss factor of 1.5 that, according to one 
commenter, increases estimated intake by 50 percent, thus increasing 
the daily MeHg intake rate by a constant factor of 33 percent and also 
increasing any resulting (HQ) risk estimate by a similar factor. 
Several commenters stated that the source of EPA's selected loss factor 
\159\ reported a range of cooking losses from 1.1 to 6. Several 
commenters cite several studies that report no or highly variable 
changes in MeHg levels as a result of cooking 
fish.160 161 162 163 164 One commenter suggested that EPA's 
cooking loss adjustment factor of 1.5 is at the high-end of the values 
supported by the literature. Another commenter stated that EPA has used 
other adjustment factors in previous documents, and that the adjustment 
factor should not be fixed across different populations given potential 
differences in cooking practices. Several commenters noted that the 
cooking loss adjustment factor should only be applied to estimates of 
consumption rates for prepared fish, and that some sources of 
consumption rates are based on raw fish.
---------------------------------------------------------------------------

    \159\ Morgan, J.N., M.R. Berry, and R.L. Graves. 1997. ``Effects 
of Commonly Used Cooking Practices on Total Mercury Concentration in 
Fish and Their Impact on Exposure Assessments.'' Journal of Exposure 
Analysis and Environmental Epidemiology 7(1):119-133.
    \160\ Armbruster G., Gerow K.G., Lisk D.J., 1988. ``The Effects 
of Six Methods of Cooking on Residues of Mercury in Striped Bass,'' 
Nutrition Reports International, 37, 123-126.
    \161\ Gutenmann, W.H. and Lisk D.J., 1991. ``Higher Average 
Mercury Concentration in Fish Fillets after Skinning and Fat 
Removal,'' Journal of Food Safety, 11, 99-103.
    \162\ Farias L.A., Favaro, D.I., Santos J.O., Vasconcellos M.B., 
et al., 2010. ``Cooking Process Evaluation on Mercury Content in 
Fish,'' Acta Amazonia, 40 (4), 741-748.
    \163\ Perell[oacute] G., Mart[iacute]-Cid R., Llobet J.M., 
Domingo J.L., 2008. ``Effects of Various Cooking Processes on the 
Concentrations of Arsenic, Cadmium, Mercury, and Lead in Foods,'' 
Journal of Agricultural and Food Chemistry, 156 (22), 11262-11269.
    \164\ Torres-Escribano S., Ruiz A., Barrios L., V[eacute]lez D., 
Montoro R., 2011. ``Influence of Mercury Bioaccessibility on 
Exposure Assessment Associated with Consumption of Cooked Predatory 
Fish in Spain,'' Journal of the Science of Food and Agriculture, 91 
(6), 981-6.
---------------------------------------------------------------------------

    Response: The EPA disagrees with the commenters that the selection 
of the cooking loss factor of 1.5 is not justified by the literature. 
The EPA also disagrees with the comment that the cooking loss 
adjustment factor of 1.5 is at the high-end of the range of values in 
the literature. The EPA selected the Morgan study \165\ as the basis 
for the food preparation/cooking adjustment factor because it focused 
on the types of freshwater fish species representative of what might be 
consumed by subsistence fishing populations (i.e., walleye and lake 
trout). This study \166\ provides a range of adjustment factors for 
each fish type including 1.1 to 1.5 for walleye and 1.5 to 2.0 for lake 
trout. Given these two ranges, the EPA determined it to be reasonable 
to take an intermediate value between the two ranges (i.e., 1.5), 
rather than focus on either the highest or lowest values, which is not 
the most conservative assumption that the EPA could have made. This 
study \167\ also explains that preparation/cooking of fish results in 
an increase in MeHg levels per unit fish because Hg concentrates in the 
muscle, while preparation/cooking tends to reduce non-muscle elements 
(e.g., water, bone, fat).
---------------------------------------------------------------------------

    \165\ Morgan et al., 1997.
    \166\ Id.
    \167\ Id.
---------------------------------------------------------------------------

    Regarding the alternative studies identified by the commenters, the 
EPA disagrees that these studies considered collectively contradict the 
cooking loss factor in the analysis. Specifically, the first study 
\168\ may have included measurement of non-fish components added to 
dishes (e.g., onions, heavy breading etc.), which could dilute the 
post-cooking Hg measurements and give the appearance of a cooking loss 
even as actual fish tissue Hg levels could have increased. In the 
second study,\169\ the fish species are saltwater and not freshwater, 
and the authors note that the reduction of water and fat could increase 
in the Hg concentration without changing absolute content. The third 
study focused on measurement of bioaccessible Hg in raw and cooked 
fish.\170\ However, available information currently allows us to 
specify the risk model in terms of total Hg intake, not bioaccessible 
Hg, thus, this article is potentially informative for guiding future 
research and methods development, not the current risk assessment. The 
fourth study \171\ found a modest but statistically insignificant 
increase in Hg levels for most of the cooking methods assessed, which 
is directionally consistent with EPA's cooking loss adjustment. The 
fifth study \172\ only addressed the issue qualitatively, thus cannot 
be used for the cooking loss factor. When considered collectively, the 
EPA disagrees that the additional studies identified by the commenter 
contradict the cooking loss factor used in the risk assessment and 
maintains that the Morgan study \173\ remains the most

[[Page 9348]]

applicable for characterizing cooking/preparation effects on Hg 
concentrations in fish.
---------------------------------------------------------------------------

    \168\ Farias et al., 2002.
    \169\ Perell[oacute] et al., 2008.
    \170\ Torres-Escribano et al., 2011.
    \171\ Armbruster et al., 1988.
    \172\ Gutenmann et al., 1991.
    \173\ Morgan et al., 1997.
---------------------------------------------------------------------------

    The EPA agrees that application of the cooking loss adjustment 
factor is appropriate if the fish consumption rates are for as cooked 
or as consumed and not for raw fish. Careful review of the three 
studies used in the risk assessment to identify subsistence fisher 
consumption rates suggests that all three represent annual-average 
daily intakes (g/day) of as consumed or as cooked fish. One study 
stated that they used models of portion or meal size servings (the size 
of the serving the respondent regularly eats).\174\ Therefore, the EPA 
interprets the fish consumption rates provided in this study \175\ as 
representing as cooked/prepared and not for raw fish and for that 
reason, application of a preparation/cooking adjustment factor is 
required. Another study \176\ used different sized models of cooked 
fish filets and therefore these consumption rates are also interpreted 
as represented as cooked/prepared and not raw fish. One study 
177 178 queried survey responders for meal portion or 
serving size and therefore, the consumption rates do represent as 
cooked/prepared. Because all three studies provide consumption rates 
based on as cooked/prepared or as consumed, it is appropriate to apply 
the cooking loss adjustment factor in modeling exposure.
---------------------------------------------------------------------------

    \174\ Burger et al., 2002.
    \175\ Id.
    \176\ Shilling, Fraser, Aubrey White, Lucas Lippert, Mark Lubell 
(2010). Contaminated fish consumption in California's Central Valley 
Delta. Environmental Research 110, p. 334-344.
    \177\ Dellinger JA. 2004. ``Exposure assessment and initial 
intervention regarding fish consumption of tribal members of the 
Upper Great Lakes Region in the United States.'' Environ Res 95:325-
340.
    \178\ Personal communication, Dr. Dellinger, September 27, 2011.
---------------------------------------------------------------------------

4. Fish Consumption Rates and Fish Tissue Hg Characterization
    Comment: One commenter stated that in the past the Agency has 
recommended various default consumption rates (in the general range of 
130 to <150 g/day) to provide default intakes for subsistence fishers 
under the Risk Assessment Guidance for Superfund (RAGS) or the Fish 
Advisory Guidance.179 180 The commenter stated that these 
default consumption rates are derived from various studies and 
generally are based on 90th or 99th percentile distribution estimates. 
Another commenter stated that EPA's use of the 99th percentile fish 
consumption for its risk analysis is inconsistent with the Agency's 
risk assessment guidelines, which recommend evaluating a reasonable 
maximum exposure (``RME'') scenario,\181 \which equates to about a 95th 
percentile fish consumption value. The same commenter stated that EPA 
applied the 99th percentile to a ``small survey of 149 South Carolina 
female anglers'' to calculate an ingestion rate of 373 grams per day 
(g/day). The commenter stated that if the 95th percentile is used the 
ingestion rate would be 173 g/day and if the default ingestion rate for 
determining ambient water standards is used the ingestion rate would be 
142 g/day.
---------------------------------------------------------------------------

    \179\ U.S. EPA. 1991. Risk Assessment Guidance for Superfund 
(RAGS). Part C 1991 EPA/9285.7-01C. October.
    \180\ U.S. EPA. 2000. National Guidance: Guidance for Assessing 
Chemical Contaminant Data for Use in Fish Advisories, Volume 2. EPA 
823-B-00-008, November.
    \181\ U.S. EPA. 1989. Risk Assessment Guidance for Superfund 
(RAGS). EPA/540/1-89/002. December.
---------------------------------------------------------------------------

    Several commenters stated that EPA based its fish consumption rates 
used in the risk analysis on a limited number of studies and that those 
studies are poorly documented.
    Another commenter stated that EPA should summarize available 
supporting studies by basic study content, characteristics, design, 
size, demographics, dietary recall period, and fish intake rates by 
demographic variables. According to the commenter, this summary would 
support the scientific validity of the assessment and better illustrate 
the potential variability and uncertainty involved in extrapolating 
data from small populations to the national-scale. The commenter also 
noted that the three studies actually used to provide subsistence 
population estimates, which were extrapolated to the national-scale, 
included a limited number of individuals living in diverse and 
localized areas.
    One commenter stated that the assumption with the greatest impact 
on risk is the fish consumption rate. That same commenter stated that 
using 99th percentile ingestion rate dramatically increases HQ and IQ 
loss compared to the 50th percentile ingestion rate. The commenter 
stated that when an estimate of the 95th percentile ingestion rate of 
the 15 to 44 year old female population is considered, the HQ is a 
tenth of the value computed with the 99th percentile high-end female 
fisher.
    One commenter stated that EPA provides broad summary statistics of 
its fish tissue data in Table 5-2 of the Regulatory Impact Analysis 
(RIA), but the summary does not allow an assessment of the 
representativeness and robustness of the underlying data for the risk 
assessment, especially at the tails of the distribution. The commenter 
stated that the table does not include a median statistic and does not 
provide any information on the number of lakes and river segments in 
each watershed. According to the commenter, an analysis of EPA's 
database by the SAB indicated that 60 percent of the watersheds with 
fish Hg data from rivers have risks calculated based upon a sample size 
of one or two fish. The commenter stated that it is not reasonable to 
base a significant policy and regulation decision on watersheds where 
exposure is based on a single fish sample in a single water body within 
it.
    Several commenters criticized EPA's use of the 75th percentile fish 
tissue MeHg level in a watershed. One commenter stated that EPA 
provided no rationale for its decision to choose the highest of the 
75th percentile for fish Hg levels among rivers and lakes within the 
HUC. Several commenters stated that subsistence fishers are less likely 
to target larger fish relative to recreational fishers. Several 
commenters suggested that EPA include a sensitivity analysis using the 
mean or median fish MeHg level in a watershed. One commenter also 
stated that EPA arbitrarily inflated the risk estimates by assuming 
consumption of only fish greater than 7 inches and choosing the largest 
of the 75th percentile of fish Hg levels from these larger fish (i.e., 
larger than 7 inches) for rivers and lakes. That same commenter 
suggested using the median of all size fish, not just those over 7 
inches.
    One commenter stated that EPA should quantify adverse effects from 
the ingestion of MeHg in seafood in addition to ingestion of MeHg from 
self-caught freshwater fish. According to the commenter, recent studies 
demonstrate that were EPA to take into account consumption of seafood, 
MeHg consumption in the U.S. is of even greater concern.
    Response: The EPA acknowledges that the focus of the Hg Risk TSD is 
characterizing risk for the groups likely to experience the greatest 
U.S. EGU-attributable Hg risk, which are subsistence fishing 
populations active at inland freshwater lakes and rivers. Specifically, 
within that subsistence fishing population, the EPA is interested in 
those individuals who are most at-risk, which includes those who 
consume the most fish. For that reason, the EPA considered a range of 
high-end fish consumption rates including the 99th percentile 
representing the most highly-exposed individuals. In responding to the 
SAB peer review, the EPA clarified this focus in the

[[Page 9349]]

introduction to the revised Hg Risk TSD and changed the full title to 
revised Technical Support Document: National-Scale Assessment of 
Mercury Risk to Populations with High Consumption of Self-caught 
Freshwater Fish.
    The EPA agrees that the fish consumption rate is an important 
factor in calculating risk from exposure to MeHg in fish. The EPA 
acknowledges that the distribution of fish consumption rates is 
positively skewed, which means that at higher percentiles (e.g., 90th, 
95th, and 99th) there is a substantial increase in ingestion rates 
relative to the mean or median. The revised Hg Risk TSD includes a 
reasonableness check on the amount of fish consumed (as a daily value) 
reflected in the different rates. While the 99th percentile consumption 
rates for the subsistence female fisher (373 g/day) is substantially 
higher than the 90th or 95th percentile values (123 and 173 g/day 
respectively), the 99th percentile value translates into a 13-ounce 
meal. While this represents a large serving, it is still reasonable if 
representing an individual who receives all of their meat protein from 
self-caught fishing, and the 13 ounces per day do not have to be eaten 
all at one meal. The higher consumption rates (i.e., greater than 250 
g/day) are supported by all three studies used in the risk assessment, 
and therefore, there is support across studies near the upper bound of 
likely consumption rates in this range. The EPA acknowledges 
uncertainty associated with estimating high-end percentile values in 
these studies due to relatively low sample sizes for some population 
groups. However, even if a few individuals reported these high self-
caught fish consumption rates, making it difficult to characterize the 
population percentiles they represent, the values still suggest that 
these levels of high fish consumption exist among surveyed individuals. 
To determine whether a public health hazard could exist, the EPA 
asserts that it is reasonable to include these consumption rates as 
representative of the most at-risk populations. In these cases, 
however, the EPA acknowledges that it is important to highlight 
uncertainty associated with characterizing the specific population 
percentile that these ingestion rates represent, and EPA has done so in 
the revised Hg Risk TSD.
    The EPA disagrees with the comment that high consumption rates are 
poorly documented. Evidence of these high fish consuming populations 
can be found in surveys \182\ and specialized 
studies.183 184 185 186 187 Several studies identified 
additional fishing populations with subsistence or near subsistence 
consumption rates, including urban fishing populations (including low-
income populations),188 189 190 Laotian communities,\191\ 
and Hispanics. The EPA participated in 1999 in a project investigating 
exposures of poor, minority communities in New York City to a number of 
contaminants including Hg, which found these populations can have very 
high fish consumption rates.\192\ The SAB concluded that the 
consumption rates and locations for fishing activity are supported by 
the data presented in the Hg Risk TSD, and are generally reasonable and 
appropriate given the available data.\193\
---------------------------------------------------------------------------

    \182\ Burger et al., 2002.
    \183\ Burger, J., K. Pflugh, L. Lurig, L. Von Hagen, and S. Von 
Hagen. 1999a. ``Fishing in Urban New Jersey: Ethnicity Affects 
Information Sources, Perception, and Compliance.'' Risk Analysis 
19(2): 217-229.
    \184\ Burger, J., Stephens, W. L., Boring, C. S., Kuklinski, M., 
Gibbons, J. W., Gochfeld M. 1999b. ``Factors in Exposure Assessment: 
Ethnic and Socioeconomic Differences in Fishing and Soncumption of 
Fish Caught along the Savannah River.'' Risk Analysis, Vol. 19, No. 
3, p. 427.
    \185\ California Environmental Protection Agency (CalEPA). 1997. 
Chemicals in Fish Report No. 1: Consumption of Fish and Shellfish in 
California and the United States Final Draft Report. Pesticide and 
Environmental Toxicology Section, Office of Environmental Health 
Hazard Assessment, July.
    \186\ Tai, S. 1999. ``Environmental Hazards and the Richmond 
Laotian American Community: A Case Study in Environmental Justice.'' 
Asian Law Journal 6: 189.
    \187\ Corburn, J. 2002. ``Combining community-based research and 
local knowledge to confront asthma and subsistence-fishing hazards 
in Greenpoint/Williamsburg, Brooklyn, New York.'' Environmental 
Health Perspectives 110(2).
    \188\ Burger et al., 1999a.
    \189\ Burger et al., 1999b.
    \190\ CalEPA, 1997.
    \191\ Tai, 1999.
    \192\ Corburn, 2002.
    \193\ U.S. EPA-SAB, 2011.
---------------------------------------------------------------------------

    The EPA agrees that the Hg Risk TSD would be improved by clarifying 
that the literature review focused on identifying studies that 
characterize subsistence fish consumption for groups active at 
freshwater locations within the U.S., and EPA has revised the Hg Risk 
TSD accordingly. In the Hg Risk TSD, the EPA summarized important study 
attributes for the source studies used to obtain fish consumption 
rates. This information was provided in Table C-1 in an appendix. To 
improve clarity, the EPA moved the summary table to the main body in 
the revised Hg Risk TSD. In identifying these studies, the EPA focused 
on surveys for subsistence fishers that were applicable at the broader 
regional or national level. In the Hg Risk TSD, the EPA acknowledged 
the smaller sample sizes for some of the subsistence fisher groups, and 
in several cases the EPA did not use the 99th percentile consumption 
rates because the sample sizes were too low to support this level of 
resolution. This decision did not affect EPA's finding of a hazard to 
public health, which is based on the results for the female subsistence 
fishing population, which has an estimate of the 99th percentile 
consumption rate that is supported by an adequate sample size.
    The EPA disagrees with the comment that it did not provide a 
rationale for choosing the 75th percentile fish tissue concentration 
across lakes and rivers in a watershed. However, the EPA modified the 
methodology based on evaluation of the number of samples within each 
watershed (responding to a recommendation from the SAB). In the revised 
methodology, the EPA computes the 75th percentile value at each 
sampling site within a watershed. The EPA then computed the average of 
the site-specific 75th percentile fish tissue Hg values within a given 
watershed. This approach does not differentiate between rivers and 
lakes and reflects an improved treatment of behavior, allowing for 
fishers to choose among multiple fishing sites within a watershed.
    The EPA generally agrees with the comment that some fraction of 
subsistence fishers likely consume fish without consideration for size 
(given dietary necessity), however, the EPA considers it reasonable to 
assume that a subset of subsistence fishers could target larger fish in 
order to maximize the potential consumption per unit of fishing effort. 
The EPA uses this subset of subsistence fishers targeting larger fish, 
which is represented by the 75th percentile fish tissue value, in the 
risk assessment. In addition, including the female subsistence fishing 
population in the analysis also provides coverage for high-end 
recreational anglers who target larger freshwater fish. The SAB 
commented that: ``Using the 75th percentile of fish tissue values as a 
reflection of consumption of larger, but not the largest, fish among 
sport and subsistence fishers is a reasonable approach and is 
consistent with published and unpublished data on predominant types of 
fish consumed.'' \194\ The SAB suggested that EPA include a sensitivity 
analysis based on use of the median value, and EPA has done so in the 
revised Hg Risk TSD. This sensitivity analysis showed that using the 
median estimates had only a small impact on the number and percent of 
modeled watersheds with

[[Page 9350]]

populations potentially at-risk from U.S. EGU-attributable MeHg 
exposures. In the revised Hg Risk TSD, the EPA clarified that the 7-
inch cutoff represents a minimum size limit for a number of key edible 
freshwater fish species established at the State-level. For example, 
Pennsylvania establishes 7 inches as the minimum size limit for both 
trout and salmon (other edible fish species such as bass, walleye and 
northern pike have higher minimum size limits).\195\
---------------------------------------------------------------------------

    \194\ U.S. EPA-SAB, 2011.
    \195\ Pennsylvania Fish and Boat Commission. 2011. Summary Book: 
2011 Pennsylvania Fishing Laws & Regulations available at: http://fishandboat.com/fishpub/summary/inland.html.
---------------------------------------------------------------------------

    The EPA disagrees with the comment that it is not reasonable to use 
watersheds where only a single fish sample is available. Although it is 
generally preferred to have multiple samples, the SAB noted that using 
a single sample is likely to underestimate the 75th percentile fish 
MeHg concentration and is, therefore, likely to underestimate the risk 
estimates for those watersheds. The SAB suggested that EPA conduct 
additional analyses of the fish tissue MeHg data, which EPA has done 
and included in the revised Hg Risk TSD. The revised Hg Risk TSD 
includes information on the number of watersheds modeled in the risk 
assessment with various fish tissue Hg samples sizes (e.g., 1, 2, 3-5, 
6-10 and >10 measurements).
5. Reference Dose (RfD) for MeHg and Hg Health Effects Studies
    Comment: Several commenters stated that EPA's RfD \196\ is based on 
sound science, which was supported by the findings of the NAS 
Study,\197\ and that EPA appropriately applied the RfD in the Hg risk 
assessment. The commenters also stated that recent studies find clear 
associations between maternal blood Hg levels and delayed child 
development and cardiovascular effects, as well as potential for 
effects due to exposure to pollutant mixtures including lead.
---------------------------------------------------------------------------

    \196\ U.S. Environmental Protection Agency--Integrated Risk 
Information System (U.S. EPA-IRIS). 2001. Methylmercury (MeHg) 
(CASRN 22967-92-6). Available at http://www.epa.gov/iris/subst/0073.htm.
    \197\ NAS, 2000.
---------------------------------------------------------------------------

    However, many commenters expressed concerns regarding EPA's use of 
the MeHg RfD as a benchmark for health risk. Several commenters raised 
concerns claiming that EPA has not incorporated the best available Hg 
toxicological data into the RfD, which results in a flawed analysis and 
an overestimate of the impact of Hg emissions on human health.
    Several commenters stated that, when deriving the RfD, the EPA 
relied on the flawed Faroe Islands' children study and ignored the 
Seychelles Islands study,\198\ which did not confirm any harm on 
children due to MeHg exposure. According to the commenters, application 
of the Faroe Island study is suspect because (1) the raw data from the 
study have never been made available for independent analysis and 
scrutiny, (2) there is potential for confounding by polychlorinated 
biphenyls (PCBs) and lead, (3) population exposure to MeHg was through 
consumption of highly contaminated pilot whale meats and blubbers, and 
(4) exposure levels in the U.S. remain lower than those observed in the 
primary study. One commenter also notes that (1) Seychelles Islanders 
consume far more fish than Americans do; (2) the amount of MeHg in the 
U.S. population is much lower than the Seychelles Islanders; and (3) 
all ocean fish contain about the same amount of MeHg, so MeHg intake 
per fish meal is similar between Americans and Seychelles Islanders. 
However, another commenter stated that industry arguments against using 
the Faroe Islands study fail to acknowledge that the study results were 
consistent with studies in the Seychelles Islands, New Zealand,\199\ 
and Poland.\200\
---------------------------------------------------------------------------

    \198\ Budtz-Jorgensen E, Debes F, Weihe P, Grandjean P. 2005. 
``Adverse Mercury Effects in 7-Year-Old Children Expressed as Loss 
in ``IQ''.'' EPA-HQ-OAR-2002-0056-6046.
    \199\ Kjellstrom, T; Kennedy, P; Wallis, S; et al. 1986. 
Physical and mental development of children with prenatal exposure 
to mercury from fish. Stage 1: Preliminary test at age 4. Natl Swed 
Environ Protec Bd, Rpt 3080 (Solna, Sweden).
    \200\ Wieslaw Jedrychowski et al. 2006. ``Effects of Prenatal 
Exposure to Mercury on Cognitive and Psychomotor Function in One-
Year-Old Infants: Epidemiologic Cohort Study in Poland,'' 16 Annals 
of Epidemiology 439.
---------------------------------------------------------------------------

    One commenter criticized EPA for using a linear dose-response model 
for the RfD-based HQ metric and the IQ metric. Another commenter stated 
that the RfD assumes a threshold dose below which an appreciable risk 
of adverse effects is unlikely, and NAS did not evaluate whether MeHg 
exposure data were better fit by a linear or non-linear model or by a 
threshold or non-threshold model.
    Several commenters stated that EPA's MeHg RfD is more conservative 
than ``safe'' levels determined by other federal agencies and claim 
that EPA assigned unusually high uncertainty factors. Several 
commenters stated that EPA's use of the 1999 National Health and 
Nutrition Examination Survey (NHANES) blood Hg levels show a downward 
trend since 1999, and the levels have been below the RfD since 2001.
    One commenter stated that a study by Texas Department of State 
Health Services (DSHS, 2004) \201\ determined that among subsistence 
fishers who eat fish from Caddo Lake with elevated MeHg, women of 
child-bearing years did not have blood Hg levels greater than the RfD. 
Thus, according to the commenter, the connection between MeHg in fish 
and adverse health effects in the U.S. is not fully understood and 
could involve other factors, including the protective effects of fatty 
acids and selenium in fish, which EPA did not taken into account.
---------------------------------------------------------------------------

    \201\ DSHS. 2005. Health Consultation: Mercury Exposure 
Investigation Caddo Lake Area-Harrison County Texas. Agency for 
Toxic Substances and Disease Registry. http://www.tceq.state.tx.us/assets/public/comm_exec/pubs/sfr/085.pdf.
---------------------------------------------------------------------------

    Two commenters claim that EPA uses the RfD as if it were an 
absolute threshold for health risk in the risk assessment even though 
the RfD methodology is a screening tool for deciding when risks clearly 
do not exist.
    Several commenters recommended adding qualitative discussions to 
the Hg Risk TSD regarding several aspects of uncertainty, including 
uncertainty in the RfD, uncertainty in extrapolating a dose-response 
relationship between MeHg exposure and change in IQ, uncertainty in 
extrapolating the dose-response relationship from marine fish and 
marine mammals to freshwater fish, and uncertainty due to potential 
confounding by PCBs in marine species.
    Several commenters raised concerns regarding the relationship 
between MeHg exposure and IQ loss. Two commenters stated that changes 
in IQ are not a well-defined health consequence of MeHg exposure. One 
commenter stated that the SAB had reservations about EPA's use of IQ 
loss. Two commenters questioned whether IQ impacts would even occur 
because in Japan and Korea, where the maternal blood Hg levels are 
higher than in the U.S., there is no evidence of adverse effects. 
Another commenter cited a study\202\ that found verbal IQ scores for 
children from mothers with no seafood intake were 50 percent more 
likely to be in the lowest quartile. One commenter questions using an 
IQ risk metric threshold of >1 or >2 points because variation in IQ 
measures and the intra-individual variation in IQ are higher than the 
threshold.
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    \202\ Hibbeln JR, Davis JM, Steer C, Emmett P, Rogers I, 
Williams C, et al., 2007. ``Maternal seafood consumption in 
pregnancy and neurodevelopmental outcomes in childhood (ALSPAC 
study): an observational cohort study. '' Lancet 369:
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    Several commenters question the relationship between cardiovascular 
effects and MeHg exposure. Two

[[Page 9351]]

commenters cited studies examining the relationship between MeHg 
exposure and cardiovascular effects,203 204 205 206 207 208 
but concluded that it seems premature to use these studies to establish 
a dose-response relationship.
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    \203\ Roman HA, Walsh TL, Coull BA, Dewailly [Eacute], Guallar 
E, Hattis D, et al., 2011. Evaluation of the Cardiovascular Effects 
of Methylmercury Exposures: Current Evidence Supports Development of 
a Dose-Response Function for Regulatory Benefits Analysis. Environ 
Health Perspect 119:607-614.
    \204\ Guallar E, Sanz-Gallardo MI, van't Veer P, et al., 2002. 
``Mercury, fish oils, and the risk of myocardial infarction.'' N 
Engl J Med.;347:1747.
    \205\ Virtanen JK, Voutilainen S, Rissanen TH, et al., 2005. 
``Mercury, fish oils, and risk of acute coronary events and 
cardiovascular disease, coronary heart disease, and all-cause 
mortality in men in eastern Finland.'' Arterioscler Thromb Vasc 
Biol. 2005;25:228.
    \206\ Yoshizawa, Rimm, Morris, Spate, Hsieh, Spiegelman, 
Stampfer, Willett. ``Mercury and the Risk of Coronary Heart Disease 
in Men,'' N Engl J Med 2002; 347:1755-1760.
    \207\ Hallgren CG, Hallmans G, Jansson JH, et al., 2001. Markers 
of high fish intake are associated with decreased risk of a first 
myocardial infarction. Br J Nutr: 86:397.
    \208\ Mozaffarian, Dariush. 2011. ``Mercury Exposure and Risk of 
Cardiovascular Disease in Two U.S. Cohorts,'' N Engl J Med 364: 
1116-1125.
---------------------------------------------------------------------------

    Several commenters assert that the risks from eating seafood are 
low relative to the benefits, that fish advisories can limit the 
beneficial aspects of fish consumption, and that fish advisories are 
often unsuccessful in changing behavior.209 210 One 
commenter noted the important protective role of dietary selenium 
against MeHg toxicity because the binding affinity of Hg to Se is much 
higher than binding to sulfur.
---------------------------------------------------------------------------

    \209\ Hibbeln et al., 2007.
    \210\ Mozaffarian, et al., 2011.
---------------------------------------------------------------------------

    Response: The EPA agrees with commenters that state the MeHg RfD is 
the appropriate health value for determining elevated risks from MeHg 
exposure and disagrees with commenters that state otherwise. At this 
time, the EPA is neither reviewing nor revising its 2001 RfD for MeHg. 
The 2001 RfD for MeHg is EPA's current peer-reviewed RfD, which is the 
value EPA uses in all its risk assessments. The EPA's RfD is based on 
multiple benchmark doses, and RfDs were calculated on various endpoints 
using the three extant large studies of childhood effects of in utero 
exposure: Faroe Islands, New Zealand, and an integrative measure 
including data from Seychelles. The EPA did not choose to base the MeHg 
RfD solely on results from the Seychelles Islands, as both the NAS 
\211\ and an independent scientific review panel convened as part of 
the IRIS process \212\ advised strongly against using results from a 
study that at the time had not shown an association between MeHg 
exposure and adverse effects. Further, the EPA disagrees with comments 
stating that EPA based the MeHg RfD solely on results from the Faroe 
Islands population and disagrees that the information underlying the 
RfD is ``poorly explained''. The EPA has provided detailed 
documentation for the choices underlying calculation of the 
RfD.213 214 215 To correct a misunderstanding by the 
commenter, the data underlying the Faroe Islands study have been 
previously published in the peer reviewed literature.
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    \211\ NAS, 2000.
    \212\ U.S. EPA. 2001b. Responses to Comments of the Peer Review 
Panel and Public Comments on Methylmercury. Available on the 
Internet at http://www.epa.gov/iris/supdocs/methpr.pdf.
    \213\ U.S. EPA, 2001a. Water Quality Criterion for the 
Protection of the Human Health: MethylmercuryEPA-823-T-01-001, 
available at http://water.epa.gov/scitech/swguidance/standards/criteria/aqlife/pollutants/methylmercury/index.cfm.
    \214\ U.S. EPA-IRIS, 2001.
    \215\ Rice D, Schoeny R, Mahaffey K. 2003. ``Methods and 
Rationale for Derivation of a Reference Dose for Methylmercury by 
the U.S. EPA.'' Risk Analysis 23(1)107-115.
---------------------------------------------------------------------------

    The EPA disagrees that it did not incorporate the latest Hg data to 
support the appropriate and necessary finding. It is the policy of EPA 
to use the most current peer reviewed, publicly available data and 
methodologies in its risk assessments. However, the EPA noted in the 
preamble to the proposed rule that ``data published since 2001 are 
generally consistent with those of the earlier studies that were the 
basis of the RfD, demonstrating persistent effects in the Faroe Island 
cohort, and in some cases associations of effects with lower MeHg 
exposure concentrations than in the Faroe Islands. These new studies 
provide additional confidence that exposures above the RfD are 
contributing to risk of adverse effects, and that reductions in 
exposures above the RfD can lead to incremental reductions in risk.'' 
However, the EPA has not completed a comprehensive review of the new 
literature, and as such, it would be premature to draw conclusions 
about the overall implications for the RfD.
    The EPA agrees that EPA's RfD is not the same as the levels used by 
other federal agencies. In their advice to the EPA on the appropriate 
bases for a MeHg RfD, NAS specifically recommended that EPA use neither 
the study nor the uncertainty factor employed by the Agency for Toxic 
Substances Disease Registry (ATSDR) in the calculation of the minimal 
risk level.\216\
---------------------------------------------------------------------------

    \216\ NAS, 2000.
---------------------------------------------------------------------------

    The EPA disagrees that the uncertainty factor is ``unusually 
high''. The uncertainty factor used in calculation of EPA's peer-
reviewed RfD is small (10 fold); half of this factor is to account for 
measured variability in human pharmacokinetics, which is based on 
advice of the NAS \217\ and an independent panel of scientific peer 
reviewers convened as part of the IRIS process.\218\
---------------------------------------------------------------------------

    \217\ Id.
    \218\ U.S. EPA, 2001b.
---------------------------------------------------------------------------

    The IRIS makes this statement regarding a threshold for MeHg, ``It 
is also important to note that no evidence of a threshold arose for 
methylmercury-related neurotoxicity within the range of exposures in 
the Faroe Islands study. This lack [of a threshold] is indicated by the 
fact that, of the K power models, K = 1 provided a better fit for the 
endpoint models than did higher values of K.'' \219\
---------------------------------------------------------------------------

    \219\ U.S. EPA-IRIS, 2001.
---------------------------------------------------------------------------

    The EPA disagrees that it is using the MeHg RfD as an absolute 
bright line for health effects in the risk assessment. As stated in the 
preamble to this proposed rule, the RfD is an estimate of a daily 
exposure to the human population that is likely to be without an 
appreciable risk of deleterious effects during a lifetime. The EPA also 
stated that no RfD defines an exposure level corresponding to zero 
risk. Because mercury is a cumulative neurotoxin, it is important to 
distinguish health effects from public health hazard. Within the 
context of the appropriate and necessary finding, we interpret a public 
health hazard as risk, rather than certain occurrence of health 
effects.
    The EPA disagrees that exposure levels in the U.S. are lower than 
those in the Faroe Islands study. Exposure to MeHg in the U.S. has been 
reported at the same levels as those published in the Faroe 
Islands.\220\ One study notes that in the NHANES data (1999 to 2004), 
the highest five percent of women's blood Hg exceeded 8.2 microgram per 
liter ([micro]g/L) in the Northeast U.S. and 7.2 [micro]g/L in coastal 
areas.\221\ Higher levels have been reported among subjects known to 
consume fish. For example, one study reported mean blood Hg for adult 
women to be 15 [micro]g/L; range for

[[Page 9352]]

men and women was 2 to 89.5 [micro]g/L.\222\ Note that some 
publications have reported Hg effects in U.S. populations at or below 
the current U.S. RfD.223 224 Also, the EPA disagrees with 
the commenter stating all ocean fish throughout the world contain about 
the same amount of MeHg. Marine fish in commerce differ widely in Hg 
concentration by species, and fish within the same species but caught 
at different locations have variable amounts of Hg in their 
tissues.225 226
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    \220\ Schober Susan E, Sinks Thomas H, Jones Robert L, Bolger P 
Michael, McDowell Margaret, Osterloh John, Garrett E Spencer, Canady 
Richard A, Dillon Charles F, Sun Yu, Joseph Catherine B, Mahaffey 
Kathryn R. Blood mercury levels in U.S. children and women of 
childbearing age, 1999-2000. JAMA. 2003 Apr 2; 289(13): 1667-1674.
    \221\ Mahaffey, K.R., R.P. Clickner and R.A. Jeffries. 2009. 
Adult Women's Blood Mercury Concentrations Vary Regionally in the 
U.S.: Association with Patterns of Fish Consumption (NHANES 1999-
2004). Environ. Health Perspect., 117: 47-53.
    \222\ Hightower Jane M, Moore Dan. Mercury levels in high-end 
consumers of fish. Environ Health Perspect. 2003 Apr; 111(4): 604-
608.
    \223\ Oken, E., Radesky, J.S., Wright, R.O., Bellinger, D.C., 
Amarasiriwardena, C.J., Kleinman, K.P., Hu, H., Gillman, M.W. 2008. 
Maternal fish Intake during Pregnancy, Blood Mercury Levels, and 
Child Cognition at Age 3 Years in a U.S. Cohort. American Journal of 
Epidemiology, 167(10), 1,171-1,181.
    \224\ Lederman, Sally Ann Robert L. Jones, Kathleen L. Caldwell, 
Virginia Rauh, Stephen E. Sheets, Deliang Tang, Sheila Viswanathan, 
Mark Becker, Janet L. Stein, Richard Y. Wang, and Frederica P. 
Perera. 2008. Relation between Cord Blood Mercury Levels and Early 
Child Development in a World Trade Center Cohort. Environmental 
Health Perspectives 118(8) 1085-1091.
    \225\ Hisamichi Y, Haraguchi K, Endo T. 2010. ``Levels of 
mercury and organochlorine compounds and stable isotope ratios in 
three tuna species taken from different regions of Japan.'' Environ 
Sci Technol 44(15): 5971-8.
    \226\ Sunderland EM. 2007. ``Mercury exposure from domestic and 
imported estuarine and marine fish in the U.S. seafood market.'' 
Environ Health Perspect. 115(2): 235-42. Epub 2006 Nov 20.
---------------------------------------------------------------------------

    The EPA disagrees that there is a statistically discernible 
downward trend in the NHANES data on blood Hg. The EPA is unaware that 
a formal statistical analysis for temporal trends has been completed 
for NHANES data on blood Hg levels for the period 1999 to 2008. 
Mahaffeyet al., evaluating NHANES data collected 1999 to 2004 for women 
at child-bearing age, could ``not support the conclusion that there was 
a general downward trend in blood Hg concentrations over the 6-year 
study period.'' \227\ However, the same publication noted that ``there 
was a decline in the upper percentiles reflecting the most highly 
exposed women'' having blood Hg concentration greater than established 
levels of concern. Visual observations of the data show a slight 
decrease in Hg blood level concentrations from 1999-2008 at the 
geometric mean, but this decrease may not be statistically significant. 
The EPA remains concerned that substantial numbers of women of 
childbearing age in the U.S. may have blood Hg levels that are 
equivalent to exposures at or above the RfD. While mean and 95th 
percentiles from recent NHANES data are below the blood Hg 
concentration equivalent to the RfD, blood levels for some portions of 
the population (high consumers of fish, for example) show exposures 
above this level. One study estimated very high blood Hg levels at the 
99th percentile for females of child-bearing age.\228\ Other published 
studies have shown that various population groups can have high blood 
Hg levels.229 230 231 232 233 For example, one study found 
that 83 percent of the NHANES Asian population exceeded the RfD-
equivalent blood mercury level.\234\
---------------------------------------------------------------------------

    \227\ Mahaffey, K.R., R.P. Clickner and R.A. Jeffries. 2009. 
Adult Women's Blood Mercury Concentrations Vary Regionally in the 
U.S.: Association with Patterns of Fish Consumption (NHANES 1999-
2004). Environ. Health Perspect., 117: 47-53.
    \228\ Tran, N.L., L. Barraj, et al., 2004. ``Combining food 
frequency and survey data to quantify long-term dietary exposure: a 
methyl mercury case study.'' Risk Anal 24(1): 19-30.
    \229\ Id.
    \230\ Miranda, M.L., S. Edwards, et al., 2011. ``Mercury levels 
in an urban pregnant population in Durham County, North Carolina.'' 
Int J Environ Res Public Health 8(3): 698-712.
    \231\ Hightower and Moore, 2003.
    \232\ Hightower, J.M., A. O'Hare, et al., (2006). ``Blood 
mercury reporting in NHANES: identifying Asian, Pacific Islander, 
Native American, and multiracial groups.'' Environ Health Perspect 
114(2): 173-175.
    \233\ McKelvey, W., R.C. Gwynn, et al., 2007. ``A biomonitoring 
study of lead, cadmium, and mercury in the blood of New York city 
adults.'' Environ Health Perspect 115(10): 1435-1441.
    \234\ Hightoweret al., 2006.
---------------------------------------------------------------------------

    The EPA disagrees with the commenter regarding confounding by PCBs 
and lead. Exposure to MeHg in the Faroe Islands was largely from 
consumption of pilot whale meat; exposure to PCBs was found in the 
portion of the population who also consume whale blubber. Numerous 
analyses have shown neurobehavioral effects of PCBs; however, the 
effects of MeHg and PCB in the Faroe Islands study are separable.\235\ 
The EPA also documented the independence of PCB and MeHg effects in the 
Faroe Islands population.\236\ The National Institute of Environmental 
Health Sciences (NIEHS) concluded that both PCB and Hg had adverse 
effects.\237\ The NAS concluded that there was no empirical evidence or 
theoretical mechanism to support the opinion that in utero Faroese 
exposure to PCBs exacerbated the reported MeHg effect.\238\ A second 
set of analyses found that the effect of prenatal PCB exposure was 
reduced when the data were sorted into tertiles by cord PCB 
concentrations.\239\ These analyses support a conclusion that there are 
measurable effects of MeHg exposure in the Faroese children that are 
not attributable to PCB toxicity. We also note that there was no report 
of lead exposure in the Faroe Islands population.
---------------------------------------------------------------------------

    \235\ NAS, 2000.
    \236\ U.S. EPA, 2001a.
    \237\ National Institute of Environmental Health Sciences 
(NIEHS). 1998. Scientific issues relevant to assessment of health 
effects from exposure to methylmercury. Workshop organized by 
Committee on Environmental and Natural Resources (CENR) Office of 
Science and Technology Policy (OSTP), The White House, November 18-
20, 1998, Raleigh, NC.
    \238\ NAS, 2000.
    \239\ Budtz-J[oslash]rgensen, E., N. Keiding, and P. Grandjean. 
1999. Benchmark modeling of the Faroese methylmercury data. Final 
Report to U.S. EPA.
---------------------------------------------------------------------------

    The EPA disagrees with the commenter's assertion that the 
connection between MeHg in fish and observed health effects is not 
understood due to evidence from the cited Texas study.\240\ This is an 
exposure study rather than a study on measures of neurobehavioral or 
any other health endpoint. TCEQ noted that none of the Caddo Lake study 
participants had blood Hg levels above the benchmark dose level (BMDL) 
of 5.8 [mu]g/L (one of the several used by EPA in the calculation of 
the MeHg RfD). The BMDL is not a ``no effect'' level. Rather it is an 
effect level for a percentage of the population. The EPA has noted in 
correspondence with TCEQ that, as an exposure study, the Caddo Lake 
study may be representative of the surrounding population; however, the 
sample size is very small. It is not appropriate to extrapolate from 
Caddo Lake to larger regional or national populations.
---------------------------------------------------------------------------

    \240\ DSHA, 2005.
---------------------------------------------------------------------------

    The EPA is aware of the possibility of both interactions among 
environmental contaminants and cumulative effects of pollutants that 
produce the same adverse endpoint. The EPA guidance exists for dealing 
with such scenarios.241 242 243 244 The Agency's concern 
with the likelihood of human exposure to multiple contaminants is

[[Page 9353]]

reflected in the multi-chemical scope of the rulemaking. However, the 
EPA focused the technical analyses supporting the proposed regulation 
on effects of individual pollutants rather than cumulative effects.
---------------------------------------------------------------------------

    \241\ U.S. EPA. 1986. Guidelines for the Health Risk Assessment 
of Chemical Mixtures. U.S. Environmental Protection Agency, Office 
of Research and Development, Washington, DC September. EPA/630/R-98/
002. Available at http://cfpub.epa.gov/ncea/cfm/recordisplay.cfm?deid=2256.
    \242\ U.S. EPA. 1999. Guidance for Performing Aggregate Exposure 
and Risk Assessments. U.S. Environmental Protection Agency, Office 
of Pesticide Programs, Washington, DC October. Available at http://www.pestlaw.com/x/guide/1999/EPA-19991029A.html.
    \243\ U.S. EPA. 2000a. Supplementary Guidance for Conducting 
Health Risk Assessment of Chemical Mixtures. U.S. Environmental 
Protection Agency, Risk Assessment Forum, Washington, DC EPA/630/R-
00/002. Available at http://www.epa.gov/ncea/raf/pdfs/chem_mix/chem_mix_08_2001.pdf.
    \244\ U.S. EPA. 2003a. Framework for Cumulative Risk Assessment. 
Risk Assessment Forum, U.S. Environmental Protection Agency. 
Washington, DC EPA/630/P-02/001F. EPA/600/P-02/001F. Available at 
http://cfpub.epa.gov/ncea/cfm/recordisplay.cfm?deid=54944.
---------------------------------------------------------------------------

    The EPA disagrees with commenters suggesting that the RfD-based HQ 
is inappropriate. The SAB ``agreed that EPA's calculation of a hazard 
quotient for each watershed included in the assessment is appropriate 
as the primary means of expressing risk,'' and that ``because the RfD 
from which the HQ is calculated is an integrative metric of 
neurodevelopmental effects of methylmercury, it constitutes a 
reasonable basis for assessing risk.'' \245\
---------------------------------------------------------------------------

    \245\ U.S. EPA-SAB, 2011.
---------------------------------------------------------------------------

    The SAB also recommended that EPA revise the Hg Risk TSD to include 
additional qualitative discussion about uncertainty in the revised Hg 
Risk TSD. Specifically, the SAB recommended that EPA revise the Hg Risk 
TSD ``to better explain the methods and choices made in the analysis, 
and analytical results, and where the uncertainties lie.'' The SAB 
noted several uncertainties related to the RfD. The EPA agrees with 
this recommendation and included a more complete discussion of these 
uncertainties in the revised Hg Risk TSD.
    The EPA disagrees that the IQ metric threshold is questionable. The 
SAB concluded that it was reasonable to consider a loss of >1 or >2 IQ 
points a public health concern. The SAB stated, ``The Panel agreed that 
if IQ loss is retained in the risk assessment despite these 
reservations, a loss of one or two points would be an appropriate 
benchmark.'' \246\ The SAB further comments in their report: ``The 
consensus is that if IQ were to be used, then a loss of 1 or 2 points 
as a population average is a credible decrement to use for this risk 
assessment. This metric seems to be derived from the lead literature 
and was peer reviewed by the Clean Air Scientific Advisory Committee 
(U.S. EPA CASAC 2007).\247\ Although its applicability to methylmercury 
is questionable, the size of the decrement is justified based on the 
extensive analyses available from the literature reviewed by CASAC.'' 
\248\  As noted in other studies,\249\ \250\ a decrease of 1-2 points 
at the mean results in a much larger decrease in those with IQs that 
are much lower or higher than the mean.
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    \246\ U.S. EPA-SAB, 2011.
    \247\ U.S. Environmental Protection Agency--Science Advisory 
Board (U.S. EPA-SAB). 2007. Clean Air Scientific Advisory 
Committee's (CASAC) Review of the 1st Draft Lead Staff Paper and 
Draft Lead Exposure and Risk Assessments. EPA-CASAC-07-003. March. 
Available on the internet at http://yosemite.epa.gov/sab/
sabproduct.nsf/989B57DCD436111B852572AC0079DA8A/$File/casac-07-
003.pdf.
    \248\ U.S. EPA-SAB, 2011.
    \249\ Axelrad, D. A.; Bellinger, D. C.; Ryan, L. M.; Woodruff, 
T. J. 2007. ``Dose-response relationship of prenatal mercury 
exposure and IQ: An integrative analysis of epidemiologic data.'' 
Environmental Health Perspectives, 115, 609-615.
    \250\ Bellinger DC. 2005. Neurobehavioral Assessments Conducted 
in the New Zealand, Faroe Islands, and Seychelles Islands Studies of 
Methylmercury Neurotoxicity in Children. Report to the U.S. 
Environmental Protection Agency. EPA-HQ-OAR-2002-0056-6045.
---------------------------------------------------------------------------

    Although EPA disagrees that the IQ results are too uncertain to 
rely upon, the EPA acknowledges that IQ is not the most sensitive 
neurodevelopmental endpoint affected by MeHg exposure, as also noted by 
the SAB. The SAB recommended that the IQ analyses be retained but be 
de-emphasized in the documentation underlying the final regulation. The 
SAB concluded, ``The Panel does not consider it appropriate to use IQ 
loss in the risk assessment and recommended that this aspect of the 
analysis be de-emphasized, moving it to an appendix where IQ loss is 
discussed along with other possible endpoints not included in the 
primary assessment. While the Panel agreed that the concentration-
response function for IQ loss used in the risk assessment is 
appropriate, and no better alternatives are available, IQ loss is not a 
sensitive response to methylmercury and its use likely underestimates 
the impact of reducing methylmercury in water bodies.'' \251\ The EPA 
is following the SAB's recommendation by deemphasizing the IQ analysis 
and placing that analysis in an appendix to the revised Hg Risk TSD.
---------------------------------------------------------------------------

    \251\ U.S. EPA-SAB, 2011.
---------------------------------------------------------------------------

    The SAB, however, supported the use of the IQ dose-response 
function calculated by EPA in the Hg Risk TSD. The SAB noted, ``The 
function used came from a paper by Axelrad and Bellinger (2007) that 
seeks to define a relationship between methylmercury exposure and IQ. A 
whitepaper by Bellinger (Bellinger, 2005) \252\ describes the sequence 
of steps in relating methylmercury exposure to maternal hair mercury 
and then that to IQ. The Mercury Risk TSD furthers notes that IQ has 
shown utility in describing the health effects of other neurotoxicants. 
These are appropriate bases for examining a potential impact of 
reducing methylmercury on IQ, but the SAB does not consider these 
compelling reasons for using IQ as a primary driver of the risk 
assessment.'' \253\
---------------------------------------------------------------------------

    \252\ Bellinger, 2005.
    \253\ U.S. EPA-SAB, 2011.
---------------------------------------------------------------------------

    The EPA disagrees that the Agency has overstated or failed to 
review the scientific literature on cardiovascular effects from MeHg 
exposure. As summarized in the preamble to the proposal, the EPA stated 
that the NAS study 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.'' \254\ The EPA also 
stated that additional cardiovascular studies have been published since 
2000. The EPA did not 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, and there is inconsistency among available studies as to the 
association between MeHg exposure and various cardiovascular system 
effects. In the future, the EPA may update the MeHg RfD and will review 
all of the relevant scientific literature available at that time, 
including data on all relevant endpoints, and weight of evidence for 
likelihood that MeHg produces specific effects in humans.
---------------------------------------------------------------------------

    \254\ 76 FR 25001.
---------------------------------------------------------------------------

    The EPA acknowledges the research regarding the effectiveness of 
fish advisories. However, the proposed regulation does not address the 
subject of fish advisories, consumer advice on fish or efficacy of such 
advice. The EPA rejects the commenter's speculation regarding whether 
the estimated IQ impacts for the regulation are real. Adverse effects 
of in utero Hg exposure have been reported in populations in the 
U.S.255 256 In another study on neurobehavioral effects of 
prenatal exposure to MeHg through maternal consumption of seafood, 
adverse effects are observed for MeHg even without controlling for fish 
consumption.\257\ That study suggests that at normal Japanese dietary 
intake of MeHg and fish nutrients, the overall effect is adverse. While 
Japanese fish consumption and Hg exposure are both somewhat higher than 
the mean U.S. exposure, these levels are still within the distribution 
of U.S. consumers.
---------------------------------------------------------------------------

    \255\ Oken et al., 2008.
    \256\ Lederman et al., 2008.
    \257\ Suzuki, K., Nakai, K., Sugawara, T., Nakamura, T., Ohba, 
T., Shimada, M., Hosokawa, T., Okamura, K., Sakai, T., Kurokawa, N., 
Murata, K., Satoh, C., and Satoh, H. 2007. ``Neurobehavioral effects 
of prenatal exposure to methylmercury and PCBs, and seafood intake: 
neonatal behavioral assessment scale results of Tohoku study of 
child development.'' Environ Res 110, 699-704.

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[[Page 9354]]

    Moreover, many studies show that beneficial effects of fish on both 
cardiovascular and neurodevelopmental health are decreased by 
concomitant exposure to MeHg. Several studies describe one or more 
aspects of exposure to fish nutrients and 
MeHg.258 259 260 261 262 263 264 Recent studies 
265 266 267 and analyses indicate the potential for 
nutrients in fish (particularly marine fish) to mask some of the 
observed adverse effects of MeHg. Because EPA did not adjust for 
potential confounding by nutrients in marine fish and mammals, the 
benchmark doses used in the RfD derivation may be underestimated.
---------------------------------------------------------------------------

    \258\ Grandjean P, Bjereve K, Wihe P, and Sterewald u. 2001a. 
``UBirthweight in a fishing community: significance of essential 
fatty acids and marine food contaminants.'' In. J. Epidemiol. 
30:1272-1278.
    \259\ Budtz-Jorgensen, E.; Grandjean, P.; Weihe, P. 2007. 
``Separation of risks and benefits of 16 seafood intake.'' 
Environmental Health Perspectives. Vol. 115, 323-327.
    \260\ Choi et al., 2008a.
    \261\ Choi et al., 2008b.
    \262\ Oken et al., 2008.
    \263\ Strain, J.J. et al., 2008. Associations of maternal long 
chain polyunsaturated fatty acids, methyl mercury, and infant 
development in the Seychelles Child Development Nutrition Study.'' 
Neurotoxicology. 29(5): 776-782.
    \264\ Suzuki, et al., 2007.
    \265\ Oken et al., 2008.
    \266\ Choi AL, Cordier S, Weihe P, Grandjean P. 2008a. 
``Negative confounding in the evaluation of toxicity: the case of 
methylmercury in fish and seafood.'' Crit Rev Toxicol. 
2008;38(10):877-93.
    \267\ Choi AL, Budtz-J[oslash]rgensen E, J[oslash]rgensen PJ, 
Steuerwald U, Debes F, Weihe P, Grandjean P. 2008b. ``Selenium as a 
potential protective factor against mercury developmental 
neurotoxicity.'' Environ Res. May;107(1):45-52. Epub 2007 Sep 12.
---------------------------------------------------------------------------

    The EPA recognizes the potential for confounding of the effects of 
Hg on the developing nervous system by a range of nutrients and 
discusses this uncertainty in the revised Hg Risk TSD. Regarding 
selenium, the SAB commented that ``one SAB member suggests the use of 
blood markers of selenium-dependent enzyme function, noting that 
methylmercury irreversibly inhibits selenium-dependent enzymes that are 
required to support vital-but-vulnerable metabolic pathways in the 
brain and endocrine system. Impaired selenoenzyme activities would be 
observed in the blood before they would be observed in brain, but the 
effect is also expected to be transitory. The use of these measures is 
a minority view among the SAB members.'' \268\ The SAB did not express 
a consensus recommendation on adjustments to the risk estimates for 
exposure to selenium or other nutrients, noting that ``there is not 
enough known about their quantitative impact to support a 
recommendation of a re-analysis.'' \269\
---------------------------------------------------------------------------

    \268\ U.S. EPA-SAB, 2011.
    \269\ Id.
---------------------------------------------------------------------------

6. General Comments on Hg Risk Assessment
    Comment: Several commenters generally supported the Hg risk 
assessment, but several other commenters generally disagreed with the 
Hg risk assessment. One supporter stated that EPA reasonably determined 
that Hg emissions pose a public health hazard, correctly requested peer 
review of Hg risk analysis and correctly concluded EGU-attributable 
MeHg poses a hazard to public health at watersheds when considering all 
sources of Hg deposition and U.S. EGUs alone. Two commenters noted that 
the contribution of U.S. EGUs to total Hg deposition can significantly 
contribute to hundreds of watersheds, and U.S. EGU deposition alone may 
endanger sensitive populations near many of these watersheds.
    Several commenters claimed that overly conservative assumptions in 
the risk analysis render the results flawed and unreliable, including 
using CMAQ to model deposition, Mercury Maps, fish consumption rate and 
fish MeHg concentrations, overly stringent RFD, national-scale model, 
using poverty as a surrogate for subsistence fishing, assuming a 
subsistence fisher resides in most watersheds with fish tissue data, 
fishers only eat larger fish with high Hg concentrations, cooking loss 
adjustment, unrealistically high fish ingestion rates (a large fish 
meal every day), focused on the extremes of the distributions, cast 
many assumptions as an underestimate of the effect despite evidence to 
the contrary, and created inappropriate metrics for risk that show no 
improvement despite significant Hg emissions reductions in the U.S.
    Several commenters cite Tetra Tech's analysis that assessed Hg risk 
using different consumption rates, cooking factor, mean fish tissue 
concentrations, and EGU-attributable Hg deposition only, which showed 
considerably fewer watersheds that exceed an HQ of 1 at 2016 deposition 
levels.
    Several commenters claim that this regulation would not 
significantly reduce Hg exposure via fish consumption because EGU-
attributable deposition is a small fraction of total deposition. One 
commenter stated that EPA's data shows Hg emissions from U.S. EGUs have 
little influence on fish Hg concentrations despite a reduction of 41 
tons of Hg in the U.S. between 2005 and 2016. One commenter requested 
that EPA accurately describe the low health risks posed by utility 
hazardous air pollutant emissions. One commenter stated that EPA did 
not consider scientific information showing that there is no 
straightforward connection between Hg emissions from U.S. EGUs to the 
Hg level in fish, which is dependent upon many environmental factors, 
such as sunlight and organic matter, pH, water temperature, sulfate, 
bacteria, and zooplankton present in the ecosystem. One commenter 
stated that there is not any demonstrable evidence that anyone in the 
U.S. has suffered adverse health problems as a result of Hg emissions 
from coal-fired EGUs. One commenter stated that EPA's findings are 
similar to the 2000 findings where EPA found a plausible link between 
anthropogenic emissions of Hg from sources in the U.S. and MeHg in 
fish, and ``plausible'' is a euphemism for unproven.
    Several commenters had recommendations for the Hg risk analysis. 
One commenter stated that more data from Florida should have been 
included because Florida is known to have a rich data set on fish Hg 
concentrations. One commenter stated that EPA should characterize 
general recreational angler fishers instead of subsistence fishers. One 
commenter claims that EPA made math errors in the Hg Risk TSD regarding 
the deposition in watersheds at specific percentiles. One commenter 
questioned EPA's policy metrics used to characterize Hg risk.
    Several commenters stated that the Hg TSD is unclear and lacks 
detail, as noted by the SAB. One commenter stated that the SAB is 
critical of EPA's efforts, stating that the SAB found it difficult to 
evaluate the risk assessment based solely upon Hg Risk TSD and 
recommended that EPA transparently explain the methods and 
uncertainties. One commenter stated that because of insufficient review 
time and the lack of detail in the Hg Risk TSD, they could not assess 
key questions, such as the nation-wide representativeness of the fish 
tissue data.
    One commenter stated the subset of watersheds considered in the 
analysis (i.e., with fish tissue data) have clearly higher U.S. EGU-
attributable deposition than the distribution of all watersheds.
    One commenter stated EPA's reporting of IQ point loss is erroneous 
and not relevant to informing policy, and the U.S. EGU contribution to 
risk is marginal as evidenced by the null values for the 50th 
percentile watershed.
    One commenter notes that U.S. EGU-attributable emissions of Hg have 
decreased significantly between 2005

[[Page 9355]]

and 2016, but claims that this decrease does not appear to affect the 
risk results.
    Response: The purpose of the Hg risk assessment is not to assess 
the magnitude of risk reduction under the proposed rule, but rather to 
estimate the magnitude of absolute risk attributable to U.S. EGUs 
currently and following implementation of other applicable CAA 
requirements. That said, any potential risk reductions following 
implementation of the MACT rule itself would likely reflect a number of 
factors besides the national average U.S. EGU deposition value cited by 
the commenter. These additional factors include: (a) Spatial gradients 
in the magnitude of absolute U.S. EGU-attributable Hg deposition, (b) 
spatial gradients in the magnitude of reductions in Hg deposition 
linked to the rule, (c) availability of measured fish tissue Hg levels 
in the vicinity of U.S. EGUs experiencing larger Hg emission reductions 
to support risk modeling, and (d) the potential for subsistence fishing 
activity at watersheds in the vicinity of U.S. EGUs experiencing larger 
reductions in Hg emissions (also required to support risk modeling). It 
is also important to point out that while the national average U.S. 
EGU-attributable Hg deposition (for the 2016 scenario--see revised Hg 
Risk TSD) is two percent, values range up to 11 percent for the 99th 
percentile watershed. This illustrates the substantial spatial 
variation in U.S. EGU-attributable Hg deposition, which translates into 
spatial variation in the magnitude of U.S. EGU-attributable subsistence 
fisher risk.
    The SAB conducted a comprehensive peer review of all of EPA's 
assumptions in the Hg Risk TSD, and concluded that ``the SAB supports 
the overall design of and approach to the risk assessment and finds 
that it should provide an objective, reasonable, and credible 
determination of the potential for a public health hazard from Hg 
emitted from U.S. EGUs.'' \270\ Furthermore, the SAB concluded, ``The 
SAB regards the design of the risk assessment as suitable for its 
intended purpose, to inform decision-making regarding an ``appropriate 
and necessary finding'' for regulation of hazardous air pollutants from 
coal and oil-fired EGUs, provided that our recommendations are fully 
considered in the revision of the assessment.'' \271\ Although the SAB 
did indicate difficulty in evaluating the risk assessment based solely 
on the Hg Risk TSD, the panel obtained additional information from EPA 
through the peer review process and determined that ``the SAB supports 
the overall design of and approach to the risk assessment and finds 
that it should provide an objective, reasonable, and credible 
determination of the potential for a public health hazard from mercury 
emitted from U.S. EGUs.'' \272\ The primary advice of the SAB panel was 
that EPA should ``revise the Technical Support Document to better 
explain the methods and choices made in the analysis, and analytical 
results, and where the uncertainties lie.'' \273\ The EPA has revised 
the Hg Risk TSD as part of the final rulemaking to address the SAB's 
recommendations and has made that revised Hg Risk TSD available in the 
rule docket.
---------------------------------------------------------------------------

    \270\ U.S. EPA-SAB, 2011.
    \271\ Id.
    \272\ Id.
    \273\ Id.
---------------------------------------------------------------------------

    The SAB concurred with EPA's analytical assumptions and overall 
study design for the Hg Risk TSD, including the RfD-based HQ approach, 
fish tissue data, 75th percentile size fish, Mercury Maps assumption, 
and consumption rates. Based on the SAB peer review, the EPA strongly 
disagrees with commenter statements that the results reported in the Hg 
Risk TSD are unreliable, overly conservative, extreme, inconsistent 
with EPA risk guidelines, or severely overstate risk based on the 
stated objectives of the analysis. The EPA has specifically addressed 
each of these assumptions in the previous sections of the preamble, and 
thus, does not repeat those responses here. Based on the review by the 
SAB, the EPA has accurately described the health risks posed by utility 
hazardous air pollutant emissions and disagrees with the commenter's 
statement that EPA has not provided any demonstrable evidence to show 
that adverse health risks exist. The EPA has applied peer reviewed 
modeling to estimate the deposition of Hg attributable to U.S. EGUs. 
The EPA asserts that these metrics demonstrate a clear hazard to public 
health from Hg emissions from U.S. EGUs.
    The EPA thoroughly evaluated the Tetra Tech analysis. The EPA does 
not agree that the analysis by Tetra Tech uses assumptions that are 
``more reasonable'', and the SAB agreed that all of EPA's assumptions 
in the Hg Risk TSD are reasonable and appropriate. The EPA asserts that 
Tetra Tech's analysis does not fully cover subsistence fishers likely 
to experience elevated U.S. EGU-related Hg exposure. Specifically, the 
risk estimate cited in the comment reflects application of a number of 
behavioral assumptions that provide significantly less coverage for 
higher risk subsistence fishers. Fish consumption surveys cited in the 
revised Hg Risk TSD suggest that higher percentile subsistence fishers 
eat more than twice the level of fish assumed by Tetra Tech. Tetra 
Tech's analysis also used the median fish tissue levels, but it is 
reasonable to assume that subsistence fishers would target somewhat 
larger fish to maximize the volume of edible meat per unit time spent 
fishing. Tetra Tech's analysis also assumed that cooking fish did not 
concentrate Hg, but a number of studies discussed in the revised Hg 
Risk TSD explicitly provide adjustment factors involving a higher unit 
concentration following preparation. Taken together, Tetra Tech's 
analysis does not address the stated goal of the risk assessment to 
assess the nature and magnitude of risk for those individuals likely to 
experience the greatest risk associated with exposure to U.S. EGU-
attributable Hg.
    The EPA disagrees with the commenter's assertion that this rule 
will not affect risks associated with Hg exposure. Hg from U.S. EGUs 
contributes to the levels of MeHg in fish across the country and 
consumption of contaminated fish can lead to increased risk of adverse 
health effects. The EPA has shown in the RIA (Chapter 5) that this rule 
will reduce Hg levels in fish.
    The EPA acknowledges that U.S. EGUs contribute only a small 
fraction of total Hg deposition in the U.S. However, U.S. EGUs remain 
the largest emitter of Hg in the U.S., and the revised Hg Risk TSD 
shows that U.S. EGU-attributable Hg deposition results in up to 29 
percent of modeled watersheds with populations potentially at-risk. Our 
analyses show that of the 29 percent of watersheds with population at-
risk, in 10 percent of those watersheds U.S. EGU deposition alone leads 
to potential exposures that exceed the MeHg RfD, and in 24 percent of 
those watersheds, total potential exposures to MeHg exceed the RfD and 
U.S. EGUs contribute at least 5 percent to Hg deposition. Mercury risk 
is increasing for exposures above the RfD, and as a result, any 
reductions in Hg exposures in locations where total exposures exceed 
the RfD can result in reduced risks. While these reductions in risk may 
be small for most populations and locations, in some watersheds and for 
some populations, reductions in risk may be greater.
    The SAB also directly addressed the question of the nation-wide 
representativeness of the fish tissue MeHg data in the national Hg risk 
assessment. The SAB concluded, ``Although the SAB considers the number 
of watersheds included in the assessment adequate, some watersheds

[[Page 9356]]

in areas with relatively high mercury deposition from U.S. EGUs were 
under-sampled due to lack of fish tissue methy[l]mercury data. The SAB 
encourages the Agency to contact states with these watersheds to 
determine if additional fish tissue methylmercury data are available to 
improve coverage of the assessment.'' \274\ In response to the SAB's 
recommendations, the EPA obtained additional fish tissue sample data 
from several states, particularly Pennsylvania, Wisconsin, Minnesota, 
New Jersey, and Michigan. This additional data increased the total 
number of watersheds assessed in the analysis by 33 percent nationally. 
In Florida, the EPA assessed the Hg-related health risk for 40 
watersheds. Because EPA did not find any additional fish tissue data 
for watersheds in Florida that could be incorporated into the analysis, 
the total number of watersheds in Florida assessed in the revised Hg 
Risk TSD remains the same as the Hg Risk TSD at proposal.
---------------------------------------------------------------------------

    \274\ U.S. EPA-SAB, 2011.
---------------------------------------------------------------------------

    The EPA disagrees with the commenter that there were errors in the 
Hg Risk TSD. Instead, the commenter has misinterpreted how EPA 
calculated the percentiles. The percentile (and mean) values presented 
in Table ES-1 for total and U.S. EGU-attributable Hg deposition are not 
matched by watershed. In other words, the EPA queried for the 
percentiles (and mean) provided for total Hg deposition and presented 
those percentiles and then separately estimated the percentiles for 
U.S. EGU-attributable Hg. Therefore, the total and U.S. EGU-
attributable values for the 99th percentile do not necessarily occur at 
the same watershed. The EPA has provided additional clarification in 
the revised Hg Risk TSD.
    The EPA agrees with the commenter that MeHg levels in fish depend 
on a complicated set of environmental factors, and EPA acknowledged 
this in the revised Hg Risk TSD. Furthermore, the EPA acknowledges that 
total Hg fish tissue levels are not correlated with levels of total Hg 
deposition when looking across watersheds because this relationship is 
highly dependent on the methylation potential at the specific 
waterbody, which is affected by pH, sulfate deposition, turbidity, etc. 
However, several recent studies 275 276 277 show, and the 
SAB agrees, that it is appropriate for EPA to assume that changes in Hg 
deposition are linearly associated with changes in fish tissue 
concentration. In addition, the EPA agrees that the subset of 
watersheds in the risk analysis have somewhat higher U.S. EGU 
deposition than the distribution of all watersheds, but EPA disagrees 
that oversampling of high deposition watersheds is inappropriate.
---------------------------------------------------------------------------

    \275\ Orihel et al., 2007.
    \276\ Orihel et al., 2008.
    \277\ Harris et al., 2007.
---------------------------------------------------------------------------

    The EPA does not agree that there is no improvement in fish Hg 
concentrations between 2005 and 2016, or that there will be no further 
improvement from decreasing Hg emissions from U.S. EGUs from the 
baseline in 2016. Although total risk from all Hg exposures will remain 
elevated in much of the U.S., much of that risk is associated with 
global, non-U.S. Hg emissions. U.S. EGUs remain the largest source of 
Hg emissions in the U.S., and reductions in those emissions will result 
in reduced Hg deposition in many highly impacted watersheds. As shown 
in the revised Hg Risk TSD, average U.S. EGU-attributable fish tissue 
Hg concentrations is estimated to decrease by 44 percent between 2005 
and 2016. Although we did not remodel risk for the 2005 scenario in the 
revised Hg Risk TSD, we estimated at proposal that the total percent of 
modeled watersheds with populations potentially at-risk from Hg 
emissions from U.S. EGUs exceeding either risk metric (i.e., U.S. EGUs 
alone or total potential exposures to MeHg exceed the RfD and U.S. EGUs 
contribute at least 5 percent) would decline from 62 percent in 2005 to 
28 percent in 2016. This projected decline is primarily due to a 
combination of additional pollution control technologies installed to 
comply with federal regulations, such as CSAPR, and changing fuels, 
such as the shift to natural gas.
    The EPA disagrees that IQ loss is erroneous or irrelevant to 
informing policy, but EPA has moved that analysis to an appendix in the 
revised Hg Risk TSD, per the SAB's recommendation. The EPA disagrees 
that the IQ effects at the 50th percentile watershed are useful in 
determining that there is not a hazard to public health because EPA's 
stated goal of the risk assessment was to focus on populations likely 
to experience relatively higher exposures to U.S. EGU-attributable Hg.
    We also disagree with those commenters that point to the SAB's 
statements concerning the clarity of the Hg Risk TSD to suggest that 
the public did not have an ample opportunity to comment on the Hg risk 
assessment. Although it is correct that the SAB said the Hg Risk TSD 
was difficult to evaluate until EPA staff explained it at the public 
meeting in June 2011, we note that the commenters that assert that this 
issue amounts to a violation of CAA section 307(d) notice requirements 
made detailed technical comments, including many of the same comments 
as the SAB. Furthermore, the EPA provided notice of the peer review in 
the preamble to the proposed rule and a number of Federal Register 
notices advised the public of the peer review process and all the 
meetings were open to the public for comment and participation and the 
minutes of those meetings were posted on the SAB Web site. The minutes 
for the June 2011 meeting, during which EPA provided clarifying 
information, were available well within the public comment period for 
the proposed rule. For these reasons, we maintain that the public was 
provided an adequate opportunity to comment on the Hg risk assessment.
e. Non-Hg HAP Case Studies
1. Emissions for Non-Hg Case Studies
    Comment: The commenters raised concerns about a wide variety of 
aspects of EPA's approach for emissions used for the non-Hg case 
studies, including the use of an arithmetic mean for computing emission 
factors for representing emissions of untested units, the suggestion of 
statistical outliers in the Cr test data, the claim that metals content 
of the fuel is an indicator of flawed test data, the statistical 
approaches used by EPA to create emission factors, the absence in EPA's 
approach of an equation that commenters claim better represents 
emissions values, that EPA's approach to estimate Cr(VI) is flawed, and 
the lack of coal rank as a delineating factor for emission factor 
calculation. The commenters also suggested that EPA should revise stack 
parameters used for the case studies based on better available data.
    Response: In response to the comments on the emission factors, the 
EPA has undertaken additional analysis to address all commenter 
concerns. The EPA disagrees with commenter's criticisms of emission 
factors based on arithmetic means, and EPA demonstrates that the use of 
an arithmetic mean provides the most representative result. The EPA 
analysis has found that the geometric mean approach recommended by the 
commenter always under predicts actual emissions by an average of more 
than seventy percent. The EPA agrees with commenters' recommendations 
to use statistical outlier tests, but has applied tests different from 
those suggested by the commenters. As further explained in the response 
to comments document in the docket, this approach did not eliminate the 
Cr test data from the Cr

[[Page 9357]]

emission factors used for some of the case study emissions.
    The EPA disagrees with commenters' assertions that the metal 
content of the coal is a basis for invalidating the test results of 
high Cr emissions. The identification of sources whose measured 
emissions do not match the commenters' preconceived idea of emissions 
behavior is not surprising. There are many possible explanations for 
these differences. For example, the inconsistency between the test data 
and the coal analysis could be due to any number of reasons including 
unrepresentative coal sampling, control device problems, degradation of 
the refractory, or sampling contamination. The idea that test data 
should be discarded because it does not match initial expectations is 
unfounded.
    The EPA disagrees with the commenter recommendations for using an 
equation from AP-42, developed in part by the commenters. Based on 
analyses of metal emissions measured at the site compared to 
statistically predicted estimates, the EPA concluded that measured 
emissions test data better predict actual emissions, and emission 
factors based on the arithmetic mean are a reasonable method to 
estimate emissions when test data are not available. The EPA analysis 
of the ICR data has found that the emissions equation recommended by 
the commenter is not a good predictor of actual EGU emissions. The EPA 
also disagrees with commenters' concerns about the assumption that 12 
percent of the Cr will be Cr(VI) for every coal-fired unit, which was 
specifically supported by the peer review on the approach for 
estimating cancer risks associated with Cr and Ni emissions. The EPA 
disagrees with the commenter's assertion that any impact of scrubbers 
will impact the case study analyses. In EPA's revised case study 
analysis, 6 facilities have risk greater than 1 in a million, and of 
these, four facilities have Cr as the risk driver (James River, 
Conesville, TVA Gallatin, and Dominion--Chesapeake Bay). For these 
facilities, none of the units contributing the bulk of the Cr emissions 
have scrubbers according to the data provided to EPA by those 
facilities, so scrubber impacts on Cr speciation is not relevant to 
EPA's conclusions based on the non-Hg case studies. In any case, the 
EPA disagrees with the commenter's conclusions about the impacts of 
scrubbers on Cr speciation and provides evidence that impacts of 
scrubbers on Cr speciation can have the opposite effect on Cr(VI) 
fractions, concluding that EPA's 12 percent assumption is somewhat 
conservative.
    The EPA also disagrees that coal rank must be a factor in computing 
Cr emission factors for use in the case studies. The EPA's analysis has 
demonstrated that coal rank appears to play no role in non-Hg metals 
emissions. The EPA's newly revised emissions factor development 
procedures can isolate and compare subgroups based on control device 
type or coal rank; the ICR data were subjected to these tests and no 
statistical significance was found between coal rank groups.
    Finally, the EPA agrees with one commenter's recommendations on 
revised stack parameters for the case studies and has included these 
revisions in the case study modeling for the final rule.
2. General Comments on Non-Hg Risk Case Study
    Comment: One commenter stated that EPA's case study assessment 
reaffirms the need to regulate HAP emitted by both coal and oil-fired 
EGUs. The commenter noted that over 40 percent of the case studies 
conducted by EPA to quantify health hazards associated with the 
inhalation of non-Hg HAP indicated a cancer risk greater than or equal 
to the one in a million threshold level required to delist a source 
category under CAA section 112.
    One commenter stated that EPA's case study assessment might be 
flawed by the use of ``beta'' tests versions of the AERMOD 
meteorological preprocessors (AERMINUTE and AERMET). The commenter 
obtained from EPA the meteorological data used for EPA's assessment of 
the Conesville facility and processed these data with EPA's current 
regulatory versions of these preprocessors, which differ from the beta 
version. According to the commenter, a comparison of the hourly wind 
speed and hourly wind direction data produced by the beta preprocessor 
and by current EPA preprocessors revealed numerous and often 
substantial disparities.
    One commenter stated that EPA's finding that only three coal-fired 
facilities and one oil-fired facility out of roughly 440 coal-fired 
facilities and 97 oil-fired facilities in the U.S. indicated risk 
greater than one-in-a-million supports a finding that it is 
``appropriate'' to regulate those four and not the other 537. Another 
commenter stated that EPA found only a ``few'' facilities that have 
estimated maximum cancer risks in excess of one in a million, and that 
this does not justify regulating all non-Hg HAP for all sources in this 
category.
    One commenter stated that EPA's discussion in the preamble to the 
proposed rule misleads the reader into believing that non-Hg HAP 
emissions from EGUs are associated with serious human health effects. 
According to the commenter, the EPA's discussion of the effects 
associated with excessive exposure to an individual HAP would lead the 
reader to believe that those effects inevitably occur from EGU 
emissions because EGU emissions have trace amounts of non-Hg HAP.
    One commenter stated that with the assumptions in the Utility 
Study, both in terms of conservative scientific estimates and 
overestimated amounts of oil burned by these units, the EPA concluded 
that the risks from oil-fired units would result in only one new cancer 
case every 5 years. The commenter does not believe that this level of 
risk warrants regulation under CAA section 112(n)(1)(A).
    Several commenters stated that even if the additional studies EPA 
performed were accurate, they hardly demonstrate that it is necessary 
and appropriate to regulate coal-fired EGU HAP under CAA section 112 
because three sites nationwide show risks greater than one in a 
million, with the highest at eight in a million.
    One commenter stated that the highest cancer risk estimated for 
coal-fired EGUs is still within the acceptable range used by EPA in 
other programs and is also far less than the background exposure risks 
the average person experiences. The background risk of developing 
cancer in a lifetime is approximately one in three (0.33). According to 
EPA's own data, the predicted added cancer risk of exposure to HAP from 
U.S. EGUs would change the background risk from 0.33 to 0.330001. This 
level of change is so minimal that it could not be observed in any 
health effects study that might be conducted.
    One commenter stated that EPA conducted a health risk assessment on 
a limited number of facilities and found a ``few'' facilities that have 
estimated maximum cancer risks in excess of one in a million. The 
commenter stated that, based on this limited health risk assessment, 
the EPA apparently decided that they were justified to regulate all 
non-Hg HAP for all sources in this category.
    Several commenters stated that EPA's assumption implies that a 
person stays exactly at the center of a census tract for 70 years and 
that a unit will operate in exactly the same manner for 70 years is 
unrealistic. The commenters suggest that Tier 3 risk assessment is 
warranted

[[Page 9358]]

or a lifetime exposure adjustment is needed.
    One commenter asserts that because the alleged health benefits are 
derived from total exposure, the EPA should explain how its numerical 
emission limit units, which would not directly restrict total exposure 
if heat inputs increase, redress this health concern. In its preamble, 
the EPA simply notes that its emission limit units are consistent with, 
and allow for simple comparison to, other regulations.
    One commenter questioned whether acid gas emissions limits for oil-
fired units are ``appropriate'' or ``necessary'' because EPA's new 
technical analyses do not indicate a health concern from acid gas 
emissions from oil-fired units. According to the commenter, the EPA 
identifies Ni as the main HAP of concern from oil-fired units, even 
though cancer-related inhalation risks were well below the RfCs and EPA 
states that significant uncertainty remains as to whether those 
emissions present a health concern.
    Response: The EPA agrees with the commenter that the non-Hg HAP 
risk assessment confirms the appropriate and necessary finding.
    The EPA disagrees that EPA's case study assessment is flawed by the 
use of beta versions of AERMINUTE and AERMET. The EPA remodeled the 
case study facilities using the current versions of AERMINUTE (version 
11059), AERMET (version 11059), and AERMOD (version 11103). Although 
there were differences in the number of calm and missing winds in the 
current AERMINUTE/AERMET output compared to the beta version, the 
resulting risks differed by less than two percent, on average. For 
Conesville, which had the largest difference in calms between the beta 
and current versions of AERMINUTE/AERMET, the risks differed by three 
percent. For the final rule, the case study facilities have been 
modeled with the current available versions of AERMINUTE, AERMET, and 
AERMOD.
    The EPA disagrees with the commenter that having only a few case 
study facilities exceeding one in a million risk invalidates the 
``appropriate finding''. The 16 facilities EPA selected as case studies 
for assessment may not represent the highest-emitting or highest-risk 
sources. Although case study facility selection criteria included high 
estimated cancer and non-cancer risks using the 2005 NEI data, high 
throughput, and minimal emission control, another necessary criterion 
was the availability of Information Collection Request (ICR) data for 
the EGUs at those facilities (or for similar EGUs at other facilities). 
Because the ICR data were collected for the purpose of developing the 
MACT standards, the ICR was targeted towards better performing sources 
for non-Hg metal HAP, acid gas HAP, and organic HAP, with a smaller set 
of random recipients. Therefore, facilities for which ICR data were 
available may not represent the highest-emitting sources. The EPA's 
assessment of the case study facilities for the proposed rule concluded 
that three coal-fired facilities and one oil-fired facility had 
estimated lifetime cancer risks greater than one in a million. For the 
final rule, revisions were made to the 16 case studies based on 
comments received, and the results indicate that 5 coal-fired 
facilities and 1 oil-fired facility had estimated lifetime cancer risks 
greater than 1 in a million. The EPA maintains that its finding that 
more than 30 percent of the case study facilities had a cancer risk 
greater than one in a million is sufficient to support the appropriate 
finding.
    The EPA disagrees with the commenter's assertion that the health 
effects associated with exposures to non-Hg HAP from U.S. EGUs are 
mischaracterized in the preamble to the proposed rule. The discussion 
of the health effects of non-Hg HAP provided in the preamble includes 
general information on the potential health effects associated with a 
broad range of exposure concentrations (from low to high levels) of the 
various non-Hg HAP (some of which have been determined to be 
carcinogenic to humans) based on peer reviewed scientific information 
extracted from priority sources such as IRIS, Cal EPA and ATSDR health 
effects assessments.
    The EPA disagrees with the commenter's characterization of the 
Utility Study. The Utility Study represented the highest-quality 
factual record of information available at the time regarding EGU 
emissions and risks. Further, the EPA's revised risk assessments of 16 
case studies, performed with more recent data and refined scientific 
methods, indicate that there are six U.S. EGU facilities that pose 
estimated inhalation cancer risks greater than 1 in a million. The EPA 
maintains that the findings of the case studies are one element that 
independently supports our determination that it remains appropriate 
and necessary to regulate EGUs under CAA section 112.
    The EPA does not agree with the commenter who suggested that EPA 
should interpret the results of the non-Hg HAP risk analysis in the 
context of background cancer risk. As explained in the preamble to the 
proposed rule, the EPA reasonably looked to the cancer risk threshold 
established under CAA section 112(c)(9)(B)(1) for delisting a source 
category as an indicator of the level of cancer risk that was 
appropriate to regulate under CAA section 112. The commenters 
comparison of the cancer risk from EGUs as compared with the risk of 
contracting cancer from unknown sources is not the standard Congress 
established for evaluating HAP emission risk and the commenter has 
provided no support for its contention that the Agency should evaluate 
risk in that manner. The EPA maintains that the analysis was 
reasonable.
    The EPA does not agree with the commenter's implication that EPA 
must make a facility-specific finding for each HAP for each source and 
then only regulate individual EGU facilities for the individual HAP 
that identified as causing an identified hazard to public health or the 
environment. That approach is not required under CAA section 112(n)(1) 
or anywhere under CAA section 112, and it would be virtually impossible 
to undertake such an effort. For these reasons, the EPA does not agree 
with the commenter and maintains that the appropriate and necessary 
finding is reasonably supported by the record and consistent with the 
statute for all the reasons set forth in the preamble to the proposed 
rule and this final action.
    The EPA disagrees that an exposure adjustment is needed to account 
for conditions changing over 70 years because it runs counter to the 
long-standing approach that EPA has taken to estimate the maximum 
individual risk, or MIR. The MIR is defined by EPA's Benzene NESHAP 
regulation of 1989 \278\ and codified by CAA section 112(f) as the 
lifetime risk for a person located at the site of maximum exposure 24 
hours a day, 365 days a year for 70 years (e.g., census block 
centroids). The MIR is the metric associated with the determination of 
whether or not a source category may be delisted from regulatory 
consideration under CAA section 112(c)(9). The MIR is the risk metric 
used to characterize the inhalation cancer risks associated with the 
case study facilities. The EPA used the annual average ambient air 
concentration of each HAP at each census block centroid as a surrogate 
for the lifetime inhalation exposure concentration of all the people 
who reside in the census block. The EPA has used this approach to 
estimate MIR values in all of its risk assessments to

[[Page 9359]]

support risk-based rulemakings under CAA section 112 to date.
---------------------------------------------------------------------------

    \278\ 54 FR 38044.
---------------------------------------------------------------------------

    The EPA disagrees with the commenter's assertion that the numerical 
emission limits being promulgated in today's final rule must be 
justified on their ability to redress the health concerns that were 
identified as the basis for regulating EGUs. The emission limits in 
today's rule are technology-based, as prescribed under CAA section 112, 
and do not need to be justified based on their ability to protect 
public health. Regarding potential health concerns, the EPA has up to 8 
years after the promulgation of the technology-based emission limits 
for EGUs to determine whether the regulations protect public health 
with an ample margin of safety. If the regulations do not, the CAA 
directs EPA to promulgate additional more stringent standards (within 
the prescribed 8 years) to achieve the appropriate level of public 
health protection.
    Furthermore, the EPA reasonably concluded that it was appropriate 
and necessary to regulate oil-fired EGUs in 2000, and EPA confirmed 
that conclusion was proper with the analysis set forth in the preamble 
to the proposed rule. Certain commenters question the determination 
based on their views of how the Agency can and should exercise its 
discretion. The EPA disagrees with these commenters and stands by the 
determination for the reasons set forth in the preamble to the proposed 
rule. The EPA also stands by the determination that the maximum cancer 
risks posed by emissions of oil-fired EGUs are greater than one in a 
million, due primarily to emissions of Ni compounds. Based on our 
analysis, we are unable to delist oil-fired EGUs.
3. Ni Risk
    Comment: Several commenters stated that the assumptions regarding 
the speciation and carcinogenic potential of Ni compounds used in EPA's 
inhalation risk assessment of the case study facilities are overly 
conservative and likely to overstate the risks. With respect to Ni 
speciation, the commenters stated that there are substantial 
uncertainties regarding the species of Ni being emitted and the risk of 
such emissions, and that EPA has made ultraconservative assumptions 
aimed at overestimating the risk. The commenters stated that assigning 
the same carcinogenic potency of Ni subsulfide to other forms of Ni is 
overly conservative and inconsistent with the best available evidence.
    Response: The EPA disagrees with the commenters' assertion that it 
is impossible to give an accurate assessment of the risks to human 
health from Ni emissions from EGUs, and maintains that its assessment 
of the potential inhalation risks from EGU emissions of Ni compounds is 
scientifically valid, reasonable, and based on the best-available 
current scientific understanding. To that end, in July 2011, the EPA 
completed an external peer review (using three independent expert 
reviewers) of the methods used to evaluate the risks from Ni and Cr 
compounds emitted by EGUs.\279\ There were two charge questions 
relating to Ni in that review. First, do EPA's judgments related to 
speciated Ni emissions adequately take into account available 
speciation data, including recent industry spectrometry studies? 
Second, based on the speciation information available and what is known 
about the health effects of Ni compounds, and taking into account the 
existing URE values (i.e., values derived by the Integrated Risk 
Information System,\280\ California Department of Health Services,\281\ 
and the Texas Commission on Environmental Quality \282\), which of the 
following approaches to derive unit risk estimates would result in a 
more accurate and defensible characterization of risks from exposure to 
Ni compounds?
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    \279\ U.S. EPA, 2011c.
    \280\ U.S. EPA, 1991.
    \281\ California Department of Health Services (CDHS) 1991. 
Health Risk Assessment for Nickel. Air Toxicology and Epidemiology 
Section, Berkeley, CA. Available online at http://oehha.ca.gov/air/toxic_contaminants/html/Nickel.htm.
    \282\ Texas Commission on Environmental Quality (TCEQ), 2011. 
Development Support Document for nickel and inorganic nickel 
compounds. Available online at http://www.tceq.state.tx.us/assets/public/implementation/tox/dsd/final/june11/nickel_&_compounds.pdf.
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    1. To continue using the same approach as that developed for use in 
the 2000 NATA, which consists of using the IRIS URE for nickel 
subsulfide and assuming that nickel subsulfide constitutes 65 percent 
of the mass emissions of all Ni compounds.
    2. To consider a more health-protective approach, based on the 
consistent views of the most authoritative scientific bodies (i.e., NTP 
in their 12th ROC, IARC, and other international agencies) that 
consider Ni compounds to be carcinogenic as a group.
    3. To make the same assumptions as in option 2, but considering 
alternative UREs derived by the CDHS or TCEQ.
    In responding to these peer review questions, two of the reviewers 
agreed with the views of the most authoritative scientific bodies, 
which consider Ni compounds carcinogenic as a group. These reviewers, 
therefore, did not focus on the availability of Ni speciation profile 
data. The third reviewer recommended that EPA review several 
manuscripts on Ni speciation profiles showing that sulfidic Ni 
compounds (which the reviewer considered as the most potent 
carcinogens) are present at low levels in emissions from EGUs.
    Nickel and Ni compounds have been classified as human carcinogens 
by national and international scientific bodies including the 
IARC,\283\ the World Health Organization,\284\ and the European Union's 
Scientific Committee on Health and Environmental Risks.\285\ In their 
12th Report of the Carcinogens, the NTP has classified Ni compounds as 
known to be human carcinogens based on sufficient evidence of 
carcinogenicity from studies in humans showing associations between 
exposure to Ni compounds and cancer, and supporting animal and 
mechanistic data. More specifically, this classification is based on 
consistent findings of increased risk of cancer in exposed workers, and 
supporting evidence from experimental animals that shows that exposure 
to an assortment of Ni compounds by multiple routes causes malignant 
tumors at various organ sites and in multiple species. The 12th Report 
of the Carcinogens states that the ``combined results of 
epidemiological studies, mechanistic studies, and carcinogenesis 
studies in rodents support the concept that Ni compounds generate Ni 
ions in target cells at sites critical for carcinogenesis, thus 
allowing consideration and evaluation of these compounds as a single 
group''.\286\ Although the precise Ni compound (or compounds) 
responsible for the carcinogenic effects in humans is not always clear, 
studies indicate that Ni sulfate and the combinations of Ni sulfides 
and oxides encountered in the Ni refining industries cause cancer in 
humans. There have been different views on whether or not Ni compounds, 
as a group, should be considered as carcinogenic to humans. Some 
authors

[[Page 9360]]

believe that water soluble Ni, such as Ni sulfate, should not be 
considered a human carcinogen, based primarily on a negative Ni sulfate 
2-year NTP rodent bioassay (which is different than the positive 2-year 
NTP bioassay for Ni subsulfide).287 288 289 Although these 
authors agree that the epidemiological data clearly supports an 
association between Ni and increased cancer risk, they sustain that the 
data are weakest regarding water soluble Ni. A recent review \290\ 
highlights the robustness and consistency of the epidemiological 
evidence across several decades showing associations between exposure 
to Ni and Ni compounds (including Ni sulfate) and cancer.
---------------------------------------------------------------------------

    \283\ International Agency for Research on Cancer (IARC), 1990. 
IARC monographs on the evaluation of carcinogenic risks to humans. 
Chromium, nickel and welding. Vol. 49. Lyons, France: International 
Agency for Research on Cancer, World Health Organization Vol. 
49:256.
    \284\ International Labour Organization/United Nations 
Environment Programme, World Health Organization (WHO), 1991. 
Nickel. In Environmental Health Criteria No 108 Geneva.
    \285\ European Commission, Scientific Committee on Health and 
Environmental Risks (SCHER), 2006. Opinion on: Reports on Nickel, 
Human Health part. SCHER, 11th plenary meeting of 04 May 2006 http://ec.europa.eu/health/ph_risk/committees/04_scher/docs/scher_o_034.pdf.
    \286\ NTP, 2011.
    \287\ Oller A. Respiratory carcinogenicity assessment of soluble 
nickel compounds. Environ Health Perspect. 2002, 110:841-844.
    \288\ Heller JG, Thornhill PG, Conard BR. New views on the 
hypothesis of respiratory cancer risk from soluble nickel exposure; 
and reconsideration of this risk's historical sources in nickel 
refineries. J Occup Med Toxicol. 2009, 4:23.
    \289\ Goodman JE, Prueitt RL, Thakali S, and Oller AR. The 
nickel iron bioavailability model of the carcinogenic potential of 
nickel-containing substances in the lung. Crit Rev Toxicol. 2011, 
41:142-174.
    \290\ Grimsrud TK and Andersen A. Evidence of carcinogenicity in 
humans of water-soluble nickel salts. J Occup Med Toxicol. 2010. 
5:1-7. Available online at http://www.ossup-med.com/content/5/1/7.
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    Based on the views of the major scientific bodies mentioned above, 
and those of expert peer reviewers that commented on EPA's approaches 
to risk characterization of Ni compounds, the EPA considers all Ni 
compounds to be carcinogenic as a group and does not consider Ni 
speciation or Ni solubility to be strong determinants of Ni 
carcinogenicity. With regards to non-cancer effects, comparative 
quantitative analysis across Ni compounds indicates that Ni sulfate is 
as toxic or more toxic than Ni subsulfide or Ni 
oxide.291 292
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    \291\ Haber LT, Allen BC, Kimmel CA. Non-Cancer Risk Assessment 
for Nickel Compounds: Issues Associated with Dose-Response Modeling 
of Inhalation and Oral Exposures. Toxicol Sci. 1998. 43:213-229.
    \292\ NTP, 1996.
---------------------------------------------------------------------------

    Regarding the second charge question, two of the reviewers 
suggested using the URE derived by TCEQ for all Ni compounds as a 
group, rather than the one derived by IRIS specifically for Ni 
subsulfide. The third reviewer did not comment on alternative 
approaches. The EPA decided to continue using 100 percent of the 
current IRIS URE for Ni subsulfide because IRIS values are at the top 
of the hierarchy with respect to the dose response information used in 
EPA's risk characterizations, and because of the concerns about the 
potential carcinogenicity of all forms of Ni raised by the major 
national and international scientific bodies. Nevertheless, taking into 
account that there are potential differences in toxicity and/or 
carcinogenic potential across the different Ni compounds, and given 
that there have been two URE values derived for exposure to mixtures of 
Ni compounds that are 2-3 fold lower than the IRIS URE for Ni 
subsulfide, the EPA also considers it reasonable to use a value that is 
50 percent of the IRIS URE for Ni subsulfide for providing an estimate 
of the lower end of a plausible range of cancer potency values for 
different mixtures of Ni compounds.
4. Cr Risk
    Comment: One commenter stated there are several problems with EPA's 
analysis related to the fact that Cr emissions were evaluated as being 
entirely Cr(VI). The commenter stated that not all of the emitted Cr 
will remain in the hexavalent form by the time it reaches the target 
population, and that some may be converted to the much less toxic (and 
noncarcinogenic) trivalent species. The commenter also stated that the 
concentration levels considered in the case study assessment are far 
below occupational levels. The commenter concluded that EPA's cancer 
estimates should, therefore, be looked on with some skepticism. Another 
commenter stated that EPA's estimate of 12 percent Cr(VI) from coal-
fired EGUs is unsupported, and that EPA failed to recognize that Cr(VI) 
is highly water-soluble and is easily reduced to Cr(III) in the 
presence of SO2 in a low pH environment. The resulting 
Cr(III) would be expected to precipitate out in a FGD. The commenter 
stated that the actual amount of Cr(VI) that would be present in the 
emissions from an EGU with a wet scrubber is likely to be far lower 
than the 12 percent estimate made by EPA.
    Several commenters questioned the validity of the chronic 
inhalation study by EPA because of (1) the use of surrogate speciated 
Cr emissions data instead of actual emissions data, (2) the assumption 
that units were run 100 percent of the time which is impossible, (3) 
dispersion modeling was used that is biased towards over predicting 
downwind impacts, and (4) estimated ambient concentrations were 
utilized as substitutes for real exposure concentrations for all people 
within a census block.
    Response: The EPA disagrees with the commenters' assertion that all 
Cr was considered to be hexavalent. As discussed in ``Methods to 
Develop Inhalation Cancer Risk Estimates for Chromium and Nickel 
Compounds,'' \293\ existing test data for utility and industrial 
boilers indicate that Cr(VI) is, on average, 12 percent of total Cr 
from coal-fired boilers. This document underwent peer review by three 
external reviewers, and all three reviewers considered EPA's use of the 
values to be reasonable given the limited data available for Cr 
speciation profiling. The EPRI inhalation study for coal-fired boilers 
also used the 12 percent value.
---------------------------------------------------------------------------

    \293\ U.S. EPA, 2011c.
---------------------------------------------------------------------------

    The EPA also disagrees that units were assumed to operate 100 
percent of the time. The dispersion modeling performed for the case 
study facilities used hourly heat input as a temporalization factor for 
estimating hourly emissions, and in some cases hourly heat inputs (and 
emissions) were zero or very low. The commenter provided no data or 
information to support their claim that the dispersion modeling EPA 
used is biased towards overestimating downwind impacts.
    The EPA disagrees with the commenters' assertion that ``real 
exposure concentrations for all people within a census block'' must be 
considered because it runs counter to the long-standing approach that 
EPA has taken to estimate the maximum individual risk, or MIR. The MIR 
is defined by EPA's Benzene NESHAP regulation of 1989 \294\ and 
codified by CAA section 112(f) as the lifetime risk for a person 
located at the site of maximum exposure 24 hours a day, 365 days a year 
for 70 years (e.g., census block centroids). The MIR is the metric 
associated with the determination of whether or not a source category 
may be delisted from regulatory consideration under CAA section 
112(c)(9). The MIR is the risk metric used to characterize the 
inhalation cancer risks associated with the case study facilities. The 
EPA used the annual average ambient air concentration of each HAP at 
each census block centroid as a surrogate for the lifetime inhalation 
exposure concentration of all the people who reside in the census 
block. The EPA has used this approach to estimate MIR values in all of 
its risk assessments to support risk-based rulemakings under CAA 
section 112 to date.
---------------------------------------------------------------------------

    \294\ 54 FR 3804.
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5. Acid Gas Risk
    Comment: One commenter stated that acid gas emissions from oil-
fired EGUs are not of the magnitude that triggered EPA's decision to 
regulate EGUs in general, raising the question of whether reduction (or 
even total elimination) of acid gas emissions from oil-fired EGUs could 
have any significant effect on EPA's goals of reducing non-cancer

[[Page 9361]]

health risk or acidification of sensitive ecosystems in the U.S.
    Several commenters stated that acid gas concentrations estimated in 
the case study facility assessment and the Utility Study do not exceed 
human health thresholds of concern. Two commenters stated that HCl 
emissions are negligible compared to other primary emissions (such as 
SO2) that can lead to potential acidification of ecosystems.
    Response: We do not agree with commenter's implication that 
Congress intended EPA to regulate only those HAP emissions from U.S. 
EGUs for which an appropriate and necessary finding is made, and 
commenter has cited no provision of the statute that states a contrary 
position. The EPA concluded that we must find it ``appropriate'' to 
regulate EGUs under CAA section 112 if we determine that a single HAP 
emitted from EGUs poses a hazard to public health or the environment. 
If we also find that regulation is necessary, the Agency is authorized 
to list EGUs pursuant to CAA section 112(c) because listing is the 
logical first step in regulating source categories that satisfy the 
statutory criteria for listing under the statutory framework of CAA 
section 112. See New Jersey, 517 F.3d at 582 (stating that ``[s]ection 
112(n)(1) governs how the Administrator decides whether to list EGUs * 
* *''). As we noted in the preamble to the proposed rule, D.C. Circuit 
precedent requires the Agency to regulate all HAP from major sources of 
HAP emissions once a source category is added to the list of categories 
under CAA section 112(c). National Lime Ass'n v. EPA, 233 F.3d 625, 633 
(D.C. Cir. 2000). 76 FR 24989. The EPA discusses in the preamble to the 
proposed rule and this final action its concerns with HCl and other 
acid gas HAP emissions from EGUs and the Agency's approach for 
establishing section 112(d) standards for acid gas HAP.
6. EPRI Risk Analysis
    Comment: Two commenters stated that a comprehensive tiered 
inhalation risk assessment (the EPRI study) using EPA-prescribed 
methods with improved emission factors, fuel data, and confirmed stack 
parameters did not identify significant health risks (cancer or non-
cancer) among U.S. coal-fired power plants (as they existed in 2007). 
The commenters noted that these results contrast with those presented 
by EPA for its non-Hg case studies on 16 (15 coal-fired) power plants. 
The commenters stated that several issues appear to underlie these 
differences, indicating the need for EPA to reevaluate its assessment 
and to undertake more refined (Tier 3) risk assessment for any facility 
of concern. Several commenters stated that for non-Hg HAP EPA produced 
one study on chronic inhalation risk assessment that identified three 
sites with cancer risks greater that one in a million for Cr(VI), which 
was authored by EPA staff and not peer reviewed. One commenter stated 
that EPA study is based on misinformation and overestimates 
assumptions, and that EPA has no data demonstrating health impacts from 
EGU emissions of non-Hg HAP, or the benefit from reducing such 
emissions. Two commenters stated that no benefits will be derived from 
the non-Hg HAP emission reductions associated with the proposed rule 
because no non-Hg HAP health risks were proven, and that no showing was 
made that EGU non-Hg HAP emission levels reach levels associated with 
adverse health effects. Another commenter stated that EPA must complete 
a comparable and separate national-scale risk assessment for non-Hg 
metals in order to determine appropriateness of proposing emissions 
standards for non-Hg metals.
    Response: The commenters are incorrect in the assertion that EPA's 
case studies were performed with less rigor than the EPRI analysis. The 
EPRI analysis used a tiered approach to risk assessment, beginning with 
Tier 1 using EPA's SCREEN3 dispersion model on all 470 coal-fired power 
plants in the U.S., and following with Tier 2 with EPA's Human Exposure 
Model (which uses the AERMOD dispersion model) for plants with higher 
risks from the Tier 1 modeling. Although tiered risk assessment is an 
appropriate approach, the Tier 2 modeling could have been more refined. 
For example, more meteorological data could have been used and building 
downwash could have been considered. The EPRI analysis ostensibly 
concluded that the Tier 2 modeling with HEM was conservative, and that 
because the modeled risks did not exceed certain thresholds, no further 
refinement was necessary. However, such refinements could result in 
higher modeled risks than those from the commenter's Tier 2 modeling.
    The EPA's dispersion modeling of the case study facilities was 
actually performed with a greater degree of refinement than the EPRI 
analysis, and was consistent with EPA's Guideline on Air Quality 
Models.\295\
---------------------------------------------------------------------------

    \295\ Appendix W to 40 CFR Part 51.
---------------------------------------------------------------------------

    In contrast to the approach used in the EPRI analysis, the EPA 
used:

    (1) 5 years of recent meteorological data from the weather 
station nearest to each facility, rather than one year of 
meteorological data. This is more representative of long-term (i.e., 
lifetime) exposures and risks.
    (2) Temporally-varying emissions based on continuous emissions 
monitoring data, rather than assuming a constant emission rate for 
each facility throughout the entire simulation.
    (3) Building downwash, where appropriate.
    (4) The latest version of AERMOD [version 11103].

    The EPA's assessment of the case study facilities for the proposed 
rule concluded that three coal-fired facilities and one oil-fired 
facility had estimated lifetime cancer risks greater than one in a 
million. For the final rule, revisions were made to the case studies 
based on comments received, and the results indicate that five coal-
fired facilities and one oil-fired facility had estimated lifetime 
cancer risks greater than one in a million.
    Regarding peer review, the risk assessment methodology used by EPA 
for the case studies was consistent with the method that EPA uses for 
assessments performed for Risk and Technology Review rulemakings, which 
underwent peer review by the Science Advisory Board in 2009.\296\ The 
SAB issued its peer review report in May 2010. The report generally 
endorsed the risk assessment methodologies used in the program. In 
addition, in July 2011, the EPA completed a letter peer review of the 
methods used to develop inhalation cancer risk estimates for Cr and Ni 
compounds.
---------------------------------------------------------------------------

    \296\ U.S. EPA-SAB, 2010.
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f. Ecosystem Impacts From HAP
    Comment: Two commenters assert that EPA is not justified in 
regulating acid gases based on concern about the potential that acid 
gases contribute to ecosystem acidification rather than concerns about 
hazards to public health. The commenters further claim that HCl's 
contribution to ecosystem acidification is de minimis. The commenters 
point out that EPA acknowledges uncertainty in quantification of 
acidification and EPA relies on recently published research \297\ that 
is irrelevant to the question since it is based on research conducted 
in the peat bog ecosystem in the United Kingdom. Another commenter 
calls attention to several new studies published in a special issue of 
the

[[Page 9362]]

journal Ecotoxicology devoted to the effects of MeHg on wildlife.
---------------------------------------------------------------------------

    \297\ Evans, Chris D., Don T. Monteith, David Fowler, J. Neil 
Cape, and Susan Brayshaw. 2011. ``Hydrochloric Acid: An Overlooked 
Driver of Environmental Change.'' Environmental Science & Technology 
45 (5), 1887-1894.
---------------------------------------------------------------------------

    Response: Although EPA agrees that quantification of acidification 
effects has remaining uncertainty, the science and methodology has 
progressed in recent years. Based on recent peer reviewed research 
including Evans et al.,\298\ acid gases can significantly contribute to 
acidification. The EPA published a comprehensive risk assessment of 
acidification effects of nitrogen and sulfur deposition \299\ and a 
policy assessment.\300\ Given the extent and importance of the 
sensitive ecosystems evaluated in the review of nitrogen and sulfur 
deposition any substance that contributes to further acidification must 
be considered to be affecting the public welfare. The EPA disagrees 
that the peer reviewed study mentioned by commenter by Evans et al., 
(2011) is not relevant to U.S. ecosystems. The paper presents evidence 
that show (1) that HCl is highly mobile in the environment, 
transferring acidity easily through soils and water, (2) that HCl can 
transport longer distances than previously thought (given its presence 
in remote ecosystems, and (3) that it can be a larger driver of 
acidification than previously thought. The fact that this study took 
place in the U.K. is itself irrelevant. The chemical interactions of 
HCl in water are the same the world over and sensitive ecosystems exist 
in the U.S. as well as in Europe as illustrated in the ecological risk 
assessment \301\ for NOX and SOX. Furthermore, 
the commenter is factually incorrect that EPA is justifying that it is 
appropriate and necessary to regulate HAP emissions from EGUs based on 
this one study. The EPA agrees with the commenter that Hg exposure in 
wildlife is responsible for various adverse health effects in many 
species across the U.S. and recognizes that research is ongoing in this 
area. As discussed in the preamble to the proposed rule, the EPA agrees 
that there are potential environmental risks from exposures of 
ecosystems through Hg and non-Hg HAP deposition. The EPA cited relevant 
articles from the special edition of Ecotoxicology \302\ mentioned by 
the commenter in the ecosystem effects section on Chapter 5 of the RIA 
for this rule, which is available in the docket.
---------------------------------------------------------------------------

    \298\ Id.
    \299\ U.S. Environmental Protection Agency (U.S. EPA). 2009. 
Risk and Exposure Assessment for Review of the Secondary National 
Ambient Air Quality Standards for Oxides of Nitrogen and Oxides of 
Sulfur (Final). EPA-452/R-09-008a. Office of Air Quality Planning 
and Standards, Research Triangle Park, NC. September. Available on 
the Internet at http://www.epa.gov/ttn/naaqs/standards/no2so2sec/data/NOxSOxREASep2009MainContent.pdf.
    \300\ U.S. Environmental Protection Agency (U.S. EPA). 2011d. 
Policy Assessment for the Review of the Secondary National Ambient 
Air Quality Standards for Oxides of Nitrogen and Oxides of Sulfur. 
EPA-452/R-11-005a. Office of Air Quality Planning and Standards, 
Research Triangle Park, NC. February. Available on the Internet at 
http://www.epa.gov/ttnnaaqs/standards/no2so2sec/data/20110204pamain.pdf.
    \301\ U.S. EPA, 2009.
    \302\ Ecotoxicology 17:83-91, 2008.
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G. EPA Affirms the Finding That It Is Appropriate and Necessary to 
Regulate EGUs To Address Public Health and Environmental Hazards 
Associated With Emissions of Hg and Non-Hg HAP From EGUs

    In response to peer reviews of both the Hg and non-Hg HAP risk 
analyses, and taking into account public comments, the EPA conducted 
revised analyses of the risks associated with emissions of Hg and non-
Hg HAP from U.S. EGUs. These revised analyses demonstrated that the 
risk results reported in the preamble to the proposed rule are robust 
to revisions in response to the peer reviews and public comments.
    Specifically, the revised Hg Risk TSD shows that up to 29 percent 
of modeled watersheds have populations potentially at-risk from 
exposure to Hg from U.S. EGUs.\303\ This 29 percent of watersheds with 
populations potentially at-risk includes up to 10 percent of modeled 
watersheds where deposition from U.S. EGUs alone leads to potential 
exposures that exceed the MeHg RfD, and up to 24 percent of modeled 
watersheds where total potential exposures to MeHg exceed the RfD and 
U.S. EGUs contribute at least 5 percent to Hg deposition. Each of these 
results independently supports our conclusion that U.S. EGUs pose 
hazards to public health.
---------------------------------------------------------------------------

    \303\ This corresponds to 28 percent of modeled watersheds with 
populations potentially at-risk in the analysis reported in the 
preamble to the proposed rule.
---------------------------------------------------------------------------

    In the preamble to the proposed rule and in the 2000 finding, the 
EPA explained at length the serious nature of the health effects 
associated with Hg exposures, and the persistent nature of Hg in the 
environment. Congress specifically recognized the significant impacts 
of persistent bioaccumulative pollutants, like Hg, when it enacted 
section 112(c)(6), which requires the EPA to subject source categories 
listed pursuant to that section to MACT standards. Congress also 
required certain studies be conducted under CAA section 112(n) 
regarding the health effects of Hg. The EPA interprets CAA section 
112(n)(1), with regard to Hg, as intended to protect the public, 
including sensitive populations, against exposures to Hg from EGUs that 
would exceed the level determined by the EPA to be without appreciable 
risk, e.g., exposures that are above the RfD for methylmercury (MeHg), 
or would contribute additional risk in areas where Hg exposures exceed 
the RfD due to contributions from all sources of Hg. Our recent 
technical analyses show that 98 percent of the watersheds for which we 
had fish tissue data have total Hg deposition such that potential 
exposures exceed the MeHg RfD, above which there is an increased risk 
of adverse effects on human health. In these watersheds, any reductions 
in exposures to Hg will reduce risk, and thus the incremental 
contribution to Hg exposure from any individual source or group of 
sources, such as EGUs, may reasonably be anticipated to cause 
additional risk.
    As we have explained, in calculating the estimates described above, 
the EPA has used peer-reviewed methods, and focused on populations 
likely to be at higher risk of exposure to Hg from U.S. EGUs, e.g., 
female subsistence fishing populations consuming at the 99th percentile 
fish consumption rate. The EPA did not, however, use the most 
conservative assumptions that would lead to upper bound risk estimates. 
As discussed above and in the revised Hg Risk TSD, we did not use the 
highest fish tissue cooking loss adjustment factor that was reported in 
the literature, which, had we done so, would have increased the 
estimates of Hg exposure substantially. Thus, we believe our analysis 
could understate risk to the most exposed individual, noting that we 
have focused on the 99th percentile consumption rate in our estimates.
    Further, we were able to assess potential Hg exposures in only a 
small subset of generally representative watersheds in the U.S. because 
our analysis was necessarily premised on those water bodies for which 
we had fish tissue Hg samples. Specifically, we analyzed 3,141 of the 
approximately 88,000 watersheds in the United States. This limited set 
of watersheds excludes several of the watersheds with the highest U.S. 
EGU attributable deposition, and may also not have included watersheds 
with the highest sensitivity to Hg deposition, e.g., the highest 
methylation rates (see above). Nevertheless, our analysis of the subset 
of watersheds we examined demonstrates that almost one third of the 
watersheds are estimated to have Hg deposition attributable to U.S. 
EGUs that contributes to potential exposures above the MeHg RfD. The 
SAB

[[Page 9363]]

confirmed that the subset of watersheds we examined is sufficient.
    Considering these points and the information on Hg in the record, 
the EPA believes that 10 percent of watersheds with populations at risk 
due to U.S. EGU emissions alone is unacceptable, as is 24 percent of 
watersheds with populations at risk due to U.S. EGU contributions in 
conjunction with total deposition from other sources. Taking into 
account the percentage of watersheds at risk, and the potential for 
even higher percentages to be at risk using more conservative risk 
assumptions and a more complete coverage of high U.S. EGU Hg deposition 
watersheds, the EPA concludes that Hg emissions from U.S. EGUs pose a 
hazard to public health.
    Given these findings, and considering that (1) the revised risk 
analysis showed the percent of modeled watersheds with populations 
potentially at-risk increased from 28 to 29 percent, and (2) the 
revised analysis includes 36 percent more watersheds, which 
significantly expands the coverage in several states, we conclude that 
the finding that emissions of Hg from U.S. EGUs pose a hazard to public 
health is confirmed by the national-scale revised Hg Risk TSD. As a 
result, we conclude that it remains appropriate to regulate Hg 
emissions from U.S. EGUs because those Hg emissions pose a hazard to 
public health.
    With regards to the revised non-Hg inhalation case studies, the 
highest estimated individual lifetime cancer risk for the one case 
study facility (out of 16) with oil-fired EGUs is estimated to be 20 in 
a million, driven by Ni emissions. For the facilities with coal-fired 
EGUs, there were five (out of 16) with maximum individual cancer risks 
greater than one in a million (the highest was five in a million), four 
of which were driven by emissions of Cr(VI), and one of which was 
driven by emissions of Ni. Therefore, a total of six facilities exceed 
the criterion for EGUs to be regulated under CAA section 112. There 
were also two facilities with coal-fired EGUs with maximum individual 
cancer risks at one in a million. In the preamble to the proposed rule, 
we reported that the maximum individual lifetime cancer risk for the 
one facility with oil-fired EGUs was estimated to be 10 in a million, 
and that there were 3 coal-fired EGU facilities with maximum individual 
cancer risks greater than 1 in a million (the highest was 8 in a 
million), and 1 coal-fired EGU facility with maximum individual cancer 
risks equal to 1 in a million. Given that (1) the lifetime cancer risk 
for the oil-fired EGU facility has increased from 10 to 20 in a 
million, (2) the number of coal-fired EGU facilities with cancer risks 
greater than 1 in a million has increased from 3 to 5, and (3) the 
highest risk coal-fired facility still has cancer risks of 5 in a 
million, which is above the 1 in a million benchmark, we conclude that 
the finding that emissions of non-Hg HAP from U.S. EGUs pose a hazard 
to public health is confirmed by the revised non-Hg risk inhalation 
case studies.
    Moreover, some HAP emissions from U.S. EGUs contribute to adverse 
ecosystem effects. While we did not do new analyses on these topics, we 
reiterate that (1) Hg emissions from U.S. EGUs pose a hazard to the 
environment, contributing to adverse impacts on fish-eating birds and 
mammals, (2) Hg is a persistent bioaccumulative environmental 
contaminant, and as a result, failing to control Hg emissions from U.S. 
EGU sources will result in long-term environmental loadings of Hg, 
above and beyond those loadings caused by immediate deposition of Hg 
within the U.S.; controlling Hg emissions from U.S. EGUs helps to 
reduce the potential for environmental hazard from Hg now and in the 
future, and (4) it is appropriate to regulate those HAP which are not 
known to cause cancer but are known to contribute to chronic non-cancer 
toxicity and environmental degradation, such as the acid gases. In 
addition, we have identified effective controls available to reduce Hg 
and non-Hg HAP emissions.
    In summary, we confirm the findings that Hg and non-Hg HAP 
emissions from U.S. EGUs each pose hazards to public health and that it 
remains appropriate to regulate U.S. EGUs under CAA section 112 for 
those reasons. We also conclude that it remains appropriate to regulate 
EGUs under CAA section 112 because of the magnitude of Hg and non-Hg 
emissions and the environmental effects of Hg and some non-Hg 
emissions, each of which standing alone, supports the appropriate 
finding. The availability of controls to reduce HAP emissions from EGUs 
only further supports the appropriate finding.
    Our revised analyses still show that in 2016 after implementation 
of other provisions of the CAA, HAP emissions from U.S. EGUs are 
reasonably anticipated to pose hazards to public health; therefore, it 
is necessary to regulate EGUs under CAA section 112. Moreover, HAP 
emissions from U.S. EGUs are expected to continue to contribute to 
adverse ecosystem effects. In addition, based on evaluation of the 
regulations required by the CAA, including the recent CSAPR, it is 
necessary to regulate U.S. EGUs under CAA section 112 because the only 
way to ensure permanent reductions in HAP emissions from U.S. EGUs and 
the associated risks to public health and the environment is through 
standards set under CAA section 112. While CSAPR is projected to 
achieve some Hg reductions due to co-control of Hg provided by controls 
put in place to achieve required reductions in SO2 
emissions, the results of the revised Hg Risk TSD indicate that an 
unacceptable percentage of modeled watersheds have populations 
potentially at-risk from U.S. EGU-attributable Hg deposition would 
remain after implementation of CSAPR. While we modeled slightly higher 
Hg emissions from U.S. EGUs (i.e., 29 tons of Hg) in our risk analysis 
compared to the most recent estimate of 27 tons, we do not believe this 
2 ton difference would substantially change our finding that Hg 
emissions from U.S. EGUs pose a hazard to public health or the Hg risks 
reported in the preamble to the proposed rule, as this represents less 
than a 10 percent reduction in Hg emissions. In addition, the actual 
reductions in Hg that will occur due to application of controls to meet 
the SO2 emissions requirements of CSAPR may differ from 
those projected to occur, due to differences in the technologies that 
individual EGU sources choose to install. The only way to ensure 
reductions in Hg, including those modeled as resulting from the CSAPR, 
is to directly regulate Hg emissions under CAA section 112.
    In summary, we confirm the findings that it is necessary to 
regulate HAP emissions from U.S. EGUs because (1) the national-scale Hg 
Risk TSD shows that the hazards to public health posed by Hg emissions 
from U.S. EGUs will not be addressed through imposition of the CAA, (2) 
we cannot be certain that the identified cancer risks attributable to 
U.S. EGUs will be addressed through imposition of the requirements of 
the CAA, (3) the environmental hazards posed by acidification will not 
be fully addressed through imposition of the CAA, (4) regulation under 
CAA section 112 is the only way to ensure that all HAP emissions 
reductions that have been achieved since 2005 remain permanent, and (5) 
direct control of Hg emissions affecting U.S. deposition is only 
possible through regulation of U.S. emissions as we are unable to 
control global emissions directly. All of these findings independently 
support a finding that it is necessary to regulate U.S. EGUs under CAA 
section 112.
    Based on these findings, the Agency affirms its finding that it 
remains appropriate and necessary to regulate

[[Page 9364]]

coal- and oil-fired EGUs under CAA section 112, and maintains that the 
inclusion of coal- and oil-fired EGUs on the CAA section 112(c) list of 
source categories regulated under CAA section 112 remains valid.

IV. Denial of Delisting Petition

    During the comment period on the proposed rule, UARG submitted a 
petition pursuant to CAA section 112(c)(9), asking the Agency to delete 
a portion of the EGU source category from the list of source categories 
to be regulated under CAA section 112. Specifically, UARG asks that EPA 
delist coal-fired EGUs from the CAA section 112(c) source category 
list. A copy of UARG's petition has been placed in the docket for 
today's rulemaking, along with the analysis conducted by EPRI that UARG 
uses to support its petition (hereinafter referred to as UARG's 
analysis). In support of its petition, UARG asserts that: (1) No coal-
fired EGU or group of coal-fired EGUs will emit HAP in amounts that 
will cause a lifetime cancer risk greater than one in one million; and 
(2) no coal-fired EGU or group of coal-fired EGUs will emit non-
carcinogenic HAP in amounts that will exceed a level which is adequate 
to protect public health with an ample margin of safety or cause 
adverse environmental effects. We disagree with UARG's assertions and 
for the reasons set forth below are denying UARG's petition to delist 
coal-fired EGUs from the section 112(c) source category list.

A. Requirements of CAA Section 112(c)(9)

    CAA section 112(c)(9)(B) provides that ``[t]he Administrator may 
delete any source category'' from the section 112(c) source category 
list if the Agency determines that: (i) For HAP that may cause cancer 
in humans, ``no source in the category (or group of sources in the case 
of area sources) emits such hazardous air pollutants in quantities 
which may cause a lifetime risk of cancer greater than one in one 
million to the individual in the population who is most exposed to 
emissions of such pollutants from the source (or group of sources in 
the case of area sources)''; and (ii) for HAP that may result in human 
health effects other than cancer or adverse environmental effects, ``a 
determination that emissions from no source in the category or 
subcategory concerned (or group of sources in the case of area sources) 
exceed a level which is adequate to protect public health with an ample 
margin of safety and no adverse environmental effect will result from 
emissions from any source.''
    The EPA has the discretion to delete a source category under CAA 
section 112(c)(9)(B), but only if EPA concludes that the relevant 
requirements of CAA section 112(c)(9)(B) have been met. HAP emissions 
from EGUs present both cancer risks, which implicate the requirements 
of CAA section 112(c)(9)(B)(i), and non-cancer human health effects or 
adverse environmental effects, which implicate the requirements of CAA 
section 112(c)(9)(B)(ii). As such, UARG bears the burden of 
demonstrating that the requirements of both clauses are met.

B. Rationale for Denying UARG's Delisting Petition

    The EPA is denying UARG's petition to delist EGUs from the CAA 
section 112(c) source category list. UARG improperly seeks to delist a 
portion of a CAA section 112(c) listed source category that emits 
carcinogens, which is contrary to the plain language of CAA section 
112(c)(9). Even setting aside this fundamental defect, UARG has failed 
to meet the requirements of CAA section 112(c)(9)(B).
1. UARG's Attempt to Delist a Portion of a Listed Source Category 
Conflicts With D.C. Circuit Precedent
    In December 2000, the EPA listed coal- and oil-fired EGUs as a 
single source category. UARG asks the Agency to delist a portion of 
that listed source category: Coal-fired EGUs. UARG's request conflicts, 
however, with D.C. Circuit precedent, which provides that for 
categories, like EGUs, that pose cancer risks, the EPA may not delist a 
portion of a source category. NRDC v. U.S. EPA, 489 F.3d 1364 (D.C. 
Cir. 2007). Specifically, in NRDC, the D.C. Circuit held that the 
Agency's attempt to delist a ``low-risk'' subcategory was ``contrary to 
the plain language of the statute,'' and that the statute only 
authorized the agency to remove source categories pursuant to section 
112(c)(9). Id. at 1373 (``Because EPA's interpretation of Section 
112(c)(9) as allowing it to exempt the risk-based subcategory is 
contrary to the plain language of the statute, the EPA's interpretation 
fails at Chevron step one.'').
    UARG's request is indistinguishable from the situation before the 
court in NRDC. UARG does not seek to delist coal- and oil-fired EGUs, 
which is the source category that EPA listed, but rather a portion of 
that category. UARG also does not dispute that coal-fired EGUs emit 
carcinogenic HAP. Because UARG's request to delist is contrary to the 
plain language of CAA section 112(c)(9)(B) and NRDC, we are denying the 
delisting petition.
2. Even Assuming, for the Sake of Argument, That EPA Could Delist a 
Portion of a Source Category, UARG has Failed to Meet the Requirements 
of CAA Section 112(c)(9)
    Even assuming, for the sake of argument, that EPA could delist a 
portion of a source category that emits carcinogens, which it cannot, 
UARG has failed to demonstrate that the requirements for delisting in 
CAA section 112(c)(9)(i) and (ii) have been met. UARG contends that it 
used EPA's models and approaches, as well as the most recent data. We 
have carefully reviewed UARG's analyses, however, and found certain 
flaws that we believe bias their risk results low. Specifically, we 
identified flaws in emissions estimation. UARG developed estimates for 
all EGU facilities using data which pre-date the 2010 ICR emissions 
measurement data that EPA obtained to support this rule. UARG also 
relied upon an emissions equation developed by EPRI and DOE to develop 
its metal emissions estimates. With regard to that approach, the EPA 
analysis of the ICR data has found that the regression approach is not 
a good predictor of actual EGU emissions. Furthermore, we found fault 
with their use of the geometric mean and their outlier analysis for 
computing emission factors. The EPA analysis has found that the 
geometric mean approach underpredicts actual emissions by an average of 
more than seventy percent. This had an especially large impact on the 
arsenic, chromium, and nickel emissions estimates. These and other 
issues are explained in further detail in the response to comments 
document. As a result, we believe the resulting risk estimates in 
UARG's analysis are biased low. In addition, we note that there are 
dispersion model refinements that are not included in the UARG 
analyses, but were included in EPA's analysis. For example, for the 
dispersion modeling of the 16 non-Hg case studies, the EPA considered 
building downwash and used time-varying emissions, neither of which 
were used in UARG's analysis. These factors could also bias the UARG 
risk estimates low.
    However, even taking UARG's analysis at face value and accepting, 
for arguments' sake, their assumptions and emissions estimates, UARG's 
own data supports denial of the petition because UARG itself identifies 
a maximum individual cancer risk exceeding 1 in a million, which is the 
statutory threshold in CAA section 112(c)(9)(B)(i). Specifically, 
UARG's multi-pathway

[[Page 9365]]

model plant ingestion risk analysis concluded that adult anglers would 
face cancer risks of 4 in a million. For this reason alone, the 
petition should be denied.
    UARG dismisses the 4 in a million cancer result, arguing that the 
refined model plant multipathway risk assessment that it conducted is 
``overly conservative.'' UARG conducted its multi-pathway risk analysis 
to evaluate the risks associated with ingesting persistent and 
bioaccumulative HAP which are emitted into the atmosphere and 
subsequently deposit into the environment and bioaccumulate in animals 
which are eventually consumed as food. Instead of conducting this 
multipathway analysis for each EGU facility, UARG instead analyzed 
multi-pathway risks by evaluating a single model plant. Nothing in the 
record indicates, however, that UARG's model plant represents the 
worst-case scenario for cancer human health risks from any EGU. Indeed, 
although UARG claims in its petition that the site selected for its 
case study is ``likely as close to a worst-case scenario as is possible 
given the numerous variables associated with ingestion pathway risks'' 
(UARG petition at 12), the supporting documentation for that case study 
specifically acknowledges that its fictional model plant scenario ``is 
not intended to represent the risk due to emissions from an actual 
plant or the highest level of risk that could be associated with a 
coal-fired power plant at any location'' (EPRI at 1). The statute 
requires that no source in the category may cause a lifetime cancer 
risk greater than one in one million to the most exposed individual, 
and UARG has failed to make this showing. UARG has neither modeled 
multi-pathway risks for a worst-case model facility, nor evaluated the 
multipathway risks associated with each individual EGU facility. 
Accordingly, UARG has not made the demonstration required by CAA 
section 112(c)(9)(B)(i). But, even focusing on the multi-pathway risk 
analysis that UARG did conduct, which admittedly does not represent a 
worst-case facility, UARG's analysis still shows cancer risks greater 
than one in a million. Accordingly, UARG's petition must be denied.
    Although it is not necessary to reach the requirements of CAA 
section 112(c)(9)(B)(ii) that address non-cancer human health risks, we 
note that UARG has also failed to show that ``emissions from no source 
in the category * * * exceed a level which is adequate to protect 
public health with an ample margin of safety.'' Again, even accepting, 
for argument's sake, the conclusions in UARG's analysis, UARG only 
evaluated the non-cancer inhalation risks associated with each EGU 
facility. It did not conduct a similar analysis to assess multipathway 
risks for each EGU facility. Instead, it conducted a model plant 
analysis and admits that such model plant does not represent the worst-
case scenario for noncancer human health risks from any EGU. Thus, the 
analysis fails to fully characterize noncancer multipathway risks for 
the source category, and UARG's petition must be denied on this basis 
as well.
    Finally, UARG failed to meet its burden of showing that ``no 
adverse environmental effect will result from emissions from any 
source'' pursuant to CAA section 112(c)(9)(B)(ii). UARG analyzed 
environmental effects only in conjunction with its model plant. Because 
UARG's model plant does not represent the worst-case scenario for 
environmental effects, UARG's analysis falls short and fails to 
characterize fully the potential environmental impacts, and UARG's 
petition must be denied.
    For all of these reasons, the EPA denies UARG's petition to delist 
coal-fired EGUs from the CAA section 112(c) source category list.

C. EPA's Technical Analyses for the Appropriate and Necessary Finding 
Provide Further Support for the Conclusion That Coal-Fired EGUs Should 
Remain a Listed Source Category

    The EPA reasonably concluded in December 2000, based on the 
information available to the Agency at that time, that it was 
appropriate and necessary to regulate coal- and oil-fired EGUs under 
CAA section 112 and added such units to the list of source categories 
subject to regulation under CAA section 112(d). As discussed in section 
III above, the EPA conducted additional, extensive technical analyses 
based on recent data that confirm it remains appropriate and necessary 
to regulate HAP from coal- and oil-fired EGUs, because such EGUs 
continue to pose hazards to public health. HAP emissions from coal- and 
oil-fired EGUs also continue to cause adverse environmental effects. 
UARG advances several arguments, challenging the analyses the Agency 
completed in support of the proposed rule. We address those arguments 
in section III above. The Agency's analyses supporting the appropriate 
and necessary finding confirm that EGUs cannot be delisted pursuant to 
CAA section 112(c)(9).
    Specifically, as explained further in section III above, the EPA 
analyzed non-Hg inhalation risks from 16 EGU facility case studies, 
including both coal- and oil-fired EGUs, as part of its technical 
analyses supporting the appropriate and necessary finding. That 
analysis demonstrates that there are 6 EGU facilities (of the 16 that 
we analyzed) with cancer risks exceeding one in one million. These 
cancer risk levels exceed the delisting criteria set forth in CAA 
section 112(c)(9)(B)(i), and confirm that EGUs must remain a listed 
source category. As explained above, some commenters assert that EPA's 
analysis of non-Hg inhalation risks from EGUs conducted in support of 
the proposal for this rulemaking overstated emissions from, and risks 
associated with, EGUs. These commenters argue that the analysis 
supporting UARG's petition more appropriately assesses EGU risk. The 
EPA disagrees with these comments and addresses these comments in 
section III above.
    Significantly, the EPA based its analysis of 16 case study EGUs 
directly on the 2010 emissions test data from EGUs obtained through the 
ICR. The EPA's 16 case study analysis used emissions data either taken 
directly from the 2010 emissions test data, or derived using emissions 
factors based on the 2010 data for similar EGU units. The EPA also 
included dispersion model refinements in its final case studies, as 
noted above. Further, the EPA re-analyzed the 16 case studies that we 
conducted for the proposal and revised those analyses consistent with 
new non-Hg HAP emissions data and corrected stack parameters provided 
by commenters (including UARG) during the comment period on the 
proposed rule. The EPA received revised information concerning 
emissions tests, stack heights and stack diameters for some of the case 
study EGU facilities. The EPA incorporated all of these corrections 
into our analysis and then re-analyzed the risks for the 16 case study 
facilities. When completed, the EPA determined that the corrections 
incorporated into the reanalysis had little effect on the overall 
results. In the final rule, the EPA concludes that the maximum 
individual inhalation cancer risks for 6 out of the 16 case study EGU 
facilities are greater than 1 in a million. These cancer risk levels 
confirm that EGUs do not satisfy the delisting criterion of CAA section 
112(c)(9)(B)(i) and thus should remain a listed source category.
    The EPA's national-scale Hg Risk TSD supporting the appropriate and 
necessary finding also confirm that Hg emissions from coal- and oil-
fired US EGUs are reasonably anticipated to pose a hazard to public 
health. As discussed

[[Page 9366]]

in section III above, the EPA interprets CAA section 112(n)(1), with 
regard to mercury, as intended to protect the public, including 
sensitive populations, against exposures to Hg from EGUs that would 
exceed the level determined by EPA to be without appreciable risk, 
e.g., exposures that are above the RfD for methylmercury (MeHg), or 
would contribute additional risk in areas where Hg exposures exceed the 
RfD due to contributions from all sources of Hg.
    In order to determine whether EGU Hg emissions pose a hazard to 
public health, the EPA conducted a national-scale Hg Risk TSD focused 
on populations with high levels of self-caught freshwater fish 
consumption. The results of the Hg Risk TSD show that 98 percent of 
modeled watersheds have total exposures to MeHg that exceed the MeHg 
RfD, above which there is an increased risk of adverse effects on human 
health. In these watersheds, any reductions in exposures to Hg will 
reduce risk, and thus the incremental contribution to Hg exposure from 
any individual source or group of sources, such as EGUs, may reasonably 
be anticipated to cause additional risk. The Hg Risk TSD focused on 
those watersheds that either exceeded the RfD based on U.S. EGU 
attributable deposition alone, without considering other sources of 
deposition, or watersheds that exceed the RfD due to total Hg 
deposition and to which U.S. EGUs contributed at least 5 percent of the 
Hg deposition. The results of that analysis show that up to 29 percent 
of the modeled watersheds have populations that are potentially at-risk 
from exposure to Hg from U.S. EGUs, including up to 10 percent of 
modeled watersheds where deposition from U.S. EGUs alone leads to 
potential exposures that exceed the MeHg RfD, and up to 24 percent of 
modeled watersheds where total potential exposures to MeHg exceed the 
RfD and U.S. EGUs contribute at least 5 percent to Hg deposition. This 
approach to assessing national risks from Hg deposition from EGUs was 
supported by the independent peer review conducted by the Science 
Advisory Board, as discussed fully in section III.
    Finally, as discussed in section III, based on this assessment, the 
EPA has confirmed that Hg emitted from U.S. EGUs pose a hazard to 
public health and it is appropriate to regulate U.S. EGUs under CAA 
section 112. This determination and the confirmatory assessments 
support our conclusion that UARG's delisting petition must be denied.
    UARG attempts to dismiss the results of EPA's national-scale Hg 
Risk TSD, arguing that EPA cannot consider the risks posed by EGUs in 
conjunction with any other risks, including those from other source 
categories. Nothing in CAA section 112(c)(9), however, provides that 
the Agency cannot consider background or emissions due to other 
sources. CAA section 112(c)(9)(B)(ii) provides that ``no source in the 
category or subcategory concerned (or group of sources in the case of 
area sources) exceed a level which is adequate to protect public health 
with an ample margin of safety and no adverse environmental effect will 
result from emissions from any source.'' This language could be read to 
provide that the Agency consider only the risks associated with the 
source category at issue, and ignore how those risks fit with real-
world exposures.\304\ However, the language could also be read to 
provide that the Agency consider the cumulative effect of HAP emissions 
from the individual sources in the category in conjunction with the HAP 
emissions from other sources. The latter is a reasonable 
interpretation, especially when considering how the public is exposed 
to HAP emissions. Considering the individual sources in a source 
category in isolation treats the sources as if they exist in a vacuum, 
which does not mirror reality. Such an approach is particularly 
problematic for environmentally persistent HAP that bio-accumulate in 
the food chain, such as mercury.\305\
---------------------------------------------------------------------------

    \304\ The same is true with respect to section 112(c)(9)(B)(i).
    \305\ In a prior rulemaking, EPA stated that the language in 
section 112(c)(9)(B)(ii) ``does not direct EPA to extend its 
analysis to either emissions from other sources in other categories 
or subcategories or to non-attributable background concentrations.'' 
71 FR 8347 (Feb. 16, 2006). The preamble to that rule repeatedly 
states that the ``focus'' of the delisting determination in that 
rule was on emissions from sources in the category under review. See 
71 FR 8346-47. The preamble went on to compare section 112(c)(9)(B) 
to section 112(f)(2)(A) in a way that suggested that EPA can 
consider risks presented by sources other than the subject source 
category under section 112(f)(2), but not under section 112(c)(9). 
We do not believe the language of section 112(c)(9) compels any 
different treatment. The section 112(f) analysis occurs after a 
source category has already complied with section 112(d) standards, 
whereas, potential delistings under section 112(c)(9) may involve 
source categories unregulated by section 112. A delisting decision 
is significant in that the category that is delisted will no longer 
be subject to HAP regulation under the Act. It is difficult to 
justify why we would examine risks from other sources under section 
112(f), but not under section 112(c)(9), where Congress established 
such a specific test for delisting.
---------------------------------------------------------------------------

    Here, the record demonstrates that 98 percent of the watersheds EPA 
modeled have total exposures to MeHg that exceed the MeHg RfD, above 
which there is increased risk of adverse effects on human health, 
especially on the developing nervous systems of children during 
gestation. EGUs remain one of the largest unregulated sources of Hg 
emissions, and those emissions continue to contribute to Hg exposures 
and risk. UARG seeks to ignore the fact that exposures above the RfD 
exist in almost every watershed we modeled, and instead focuses on the 
contribution provided solely by EGUs. The EPA did as UARG asked and 
found that up to 10 percent of modeled watersheds where deposition from 
U.S. EGUs alone leads to potential exposures that exceed the MeHg RfD. 
Thus, even focusing on EGU emissions in a vacuum, which we do not 
believe is appropriate or required under CAA section 112(c)(9), we 
still found that up to 10 percent of the watersheds exceed the RfD due 
to EGU emissions even before taking into account the numerous other 
sources of Hg deposition, and we believe this to be an unacceptable 
percentage of watersheds above the RfD. Due to the persistent, 
bioacccumulative nature of Hg, among other factors, we believe it is 
appropriate to consider the combined impact of Hg emissions from EGUs 
and other sources of Hg. Thus, we also considered the 24 percent of 
modeled watersheds where, even though U.S. EGU emissions alone are not 
enough to cause exposures that exceed the RfD, those emissions 
contribute at least 5 percent of total exposures to MeHg that exceed 
the RfD. The combined total of 29 percent of modeled watersheds where 
U.S. EGUs cause or contribute to MeHg exposures above the RfD is 
clearly unacceptable and thus the UARG petition to delist must be 
denied.
    Thus, the technical analyses the Agency conducted in support of the 
appropriate and necessary finding confirm that EGUs should remain a 
listed source category.

V. Summary of This Final NESHAP

    This section summarizes the requirements of the final EGU NESHAP. 
Section VI below summarizes the significant changes to this final rule 
following proposal.

A. What is the source category regulated by this final rule?

    This final rule affects coal- and oil-fired EGUs.

B. What is the affected source?

    An existing affected source under this final rule is the collection 
of coal- or oil-fired EGUs in a subcategory within a single contiguous 
area and under common control. A new affected source is each coal- or 
oil-fired EGU for which construction or reconstruction began after May 
3, 2011.


[[Page 9367]]


    CAA section 112(a)(8) defines an EGU as: a fossil fuel-fired 
combustion unit of more than 25 megawatts that serves a generator 
that produces electricity for sale. A unit that cogenerates steam 
and electricity and supplies more than one-third of its potential 
electric output capacity and more than 25 megawatts electrical 
output to any utility power distribution system for sale shall be 
considered an electric utility steam generating unit.

    If an EGU burns coal (either as a primary fuel or as a 
supplementary fuel) or any combination of coal with another fuel 
(except for solid waste as noted below) where the coal accounts for 
more than 10.0 percent of the average annual heat input during any 3 
consecutive calendar years or for more than 15.0 percent of the annual 
heat input during any one calendar year after the applicable compliance 
date, the unit is considered to be coal-fired under this final rule.
    If a unit is not a coal-fired unit and burns only oil or burns oil 
in combination with a fuel other than coal (except solid waste as noted 
below) where the oil accounts for more than 10.0 percent of the average 
annual heat input during any 3 consecutive calendar years or for more 
than 15.0 percent of the annual heat input during any one calendar year 
after the applicable compliance date, the unit is considered to be oil-
fired under this final rule.
    As noted below, the EPA is finalizing in this rule a definition to 
determine whether the combustion unit is ``fossil fuel fired'' such 
that it is considered an EGU as defined in CAA section 112(a)(8) and, 
thus, potentially subject to this final rule. In addition, using the 
construct of the definition of ``oil-fired'' from the ARP, we are 
finalizing in this rule a requirement that the unit fire coal or oil 
(or natural gas), or any combination thereof, for more than 10.0 
percent of the average annual heat input during any 3 consecutive 
calendar years or for more than 15.0 percent of the annual heat input 
during any one calendar year to be considered a ``fossil fuel-fired'' 
EGU as defined in CAA section 112(a)(8). However, if a new or existing 
EGU is not coal- or oil-fired, and the unit burns natural gas 
exclusively or burns natural gas in combination with another fuel where 
the natural gas constitutes 10 percent or more of the average annual 
heat input during any 3 calendar years or 15 percent or more of the 
annual heat input during any 1 calendar year, the unit is considered to 
be natural gas-fired EGU and not subject to this final rule. As 
discussed later, we believe that this definition will address those 
situations where an EGU co-fires limited amounts of either coal or oil 
with natural gas or other non-fossil fuels (e.g., biomass).
    If an EGU combusts solid waste, standards issued pursuant to CAA 
section 129 apply to that EGU, rather than this final rule.

C. What are the pollutants regulated by this final rule?

    For coal-fired EGUs, this final rule regulates HCl as a surrogate 
for acid gas HAP, with an alternate of SO2 as a surrogate 
for acid gas HAP for coal-fired EGUs with FGD systems installed and 
operational; filterable PM as a surrogate for non-mercury HAP metals, 
with total non-mercury HAP metals and individual non-mercury HAP metals 
as alternative equivalent standards; Hg; and organic HAP. For oil-fired 
EGUs, this final rule regulates HCl and HF; filterable PM as a 
surrogate for total HAP metals, with individual HAP metals as 
alternative equivalent standards; and organic HAP.

D. What emission limits and work practice standards must I meet and 
what are the subcategories in the final rule?

    We are finalizing the emission limitations presented in Tables 3 
and 4 of this preamble. Within the two major subcategories of ``coal'' 
and ``oil,'' emission limitations were developed for new and existing 
sources for seven subcategories, two for coal-fired EGUs, one for IGCC 
EGUs burning synthetic gas derived from coal- and/or solid oil-derived 
fuel, one for solid oil-derived fuel-fired EGUs, and four for liquid 
oil-fired EGUs, as described in more detail below. The limited-use 
liquid oil-fired subcategory, discussed elsewhere in this preamble, is 
not presented in Table 3 because only work practice standards apply to 
this subcategory.

               Table 3--Emission Limitations for Coal-Fired and Solid Oil-Derived Fuel-Fired EGUs
----------------------------------------------------------------------------------------------------------------
                                     Filterable particulate
           Subcategory                       matter              Hydrogen  chloride              Mercury
----------------------------------------------------------------------------------------------------------------
Existing--Unit not low rank        3.0E-2 lb/MMBtu..........  2.0E-3 lb/MMBtu.........  1.2E0 lb/TBtu.
 virgin coal.                      (3.0E-1 lb/MWh)..........  (2.0E-2 lb/MWh).........  (1.3E-2 lb/GWh).
Existing--Unit designed low rank   3.0E-2 lb/MMBtu..........  2.0E-3 lb/MMBtu.........  1.1E+1 lb/TBtu.
 virgin coal.                      (3.0E-1 lb/MWh)..........  (2.0E-2 lb/MWh).........  (1.2E-1 lb/GWh).
                                                                                        4.0E0 lb/TBtu \a\.
                                                                                        (4.0E-2 lb/GWh \a\).
Existing--IGCC...................  4.0E-2 lb/MMBtu..........  5.0E-4 lb/MMBtu.........  2.5E0 lb/TBtu.
                                   (4.0E-1 lb/MWh)..........  (5.0E-3 lb/MWh).........  (3.0E-2 lb/GWh).
Existing--Solid oil-derived......  8.0E-3 lb/MMBtu..........  5.0E-3 lb/MMBtu.........  2.0E-1 lb/TBtu.
                                   (9.0E-2 lb/MWh)..........  (8.0E-2 lb/MWh).........  (2.0E-3 lb/GWh).
New--Unit not low rank virgin      7.0E-3 lb/MWh............  4.0E-4 lb/MWh...........  2.0E-4 lb/GWh.
 coal.
New--Unit designed for low rank    7.0E-3 lb/MWh............  4.0E-4 lb/MWh...........  4.0E-2 lb/GWh.
 virgin coal.
New--IGCC........................  7.0E-2 lb/MWh \b\........  2.0E-3 lb/MWh \d\.......  3.0E-3 lb/GWh \e\.
                                   9.0E-2 lb/MWh \c\........
New--Solid oil-derived...........  2.0E-2 lb/MWh............  4.0E-4 lb/MWh...........  2.0E-3 lb/GWh.
----------------------------------------------------------------------------------------------------------------
Note: lb/MMBtu = pounds pollutant per million British thermal units fuel input.
lb/TBtu = pounds pollutant per trillion British thermal units fuel input.
lb/MWh = pounds pollutant per megawatt-hour electric output (gross).
lb/GWh = pounds pollutant per gigawatt-hour electric output (gross).
\a\ Beyond-the-floor limit as discussed elsewhere.
\b\ Duct burners on syngas; based on permit levels in comments received.

[[Page 9368]]

 
\c\ Duct burners on natural gas; based on permit levels in comments received.
\d\ Based on best-performing similar source.
\e\ Based on permit levels in comments received.


                             Table 4--Emission Limitations for Liquid Oil-Fired EGUs
----------------------------------------------------------------------------------------------------------------
                                  Filterable particulate
          Subcategory                     matter                Hydrogen  chloride         Hydrogen  fluoride
----------------------------------------------------------------------------------------------------------------
Existing--Liquid oil--          3.0E-2 lb/MMBtu...........  2.0E-3 lb/MMBtu..........  4.0E-4 lb/MMBtu.
 continental.                   (3.0E-1 lb/MWh)...........  (1.0E-2 lb/MWh)..........  (4.0E-3 lb/MWh).
Existing--Liquid oil--non-      3.0E-2 lb/MMBtu...........  2.0E-4 lb/MMBtu..........  6.0E-5 lb/MMBtu.
 continental.                   (3.0E-1 lb/MWh)...........  (2.0E-3 lb/MWh)..........  (5.0E-4 lb/MWh).
New--Liquid oil--continental..  7.0E-2 lb/MWh.............  4.0E-4 lb/MWh............  4.0E-4 lb/MWh.
New--Liquid oil--non-           2.0E-1 lb/MWh.............  2.0E-3 lb/MWh............  5.0E-4 lb/MWh.
 continental.
----------------------------------------------------------------------------------------------------------------

    We are also finalizing alternate equivalent emission standards (for 
certain subcategories) to the final surrogate standards in three areas: 
SO2 (for HCl), individual non-mercury metals and total non-
mercury metals (for filterable PM) from coal- and solid oil-derived 
fuel-fired EGUs, and individual and total metals (for filterable PM) 
from oil-fired EGUs. The final alternate emission limitations are 
provided in Tables 5 and 6 of this preamble.

                                                          Table 5--Alternate Emission Limitations for Existing Coal- and Oil-Fired EGUs
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
       Subcategory/Pollutant                Coal-fired EGUs                      IGCC                   Liquid oil, continental      Liquid oil, non-continental         Solid oil- derived
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
SO2...............................  2.0E-1 lb/MMBtu...............  NA............................  NA............................  NA...........................  3.0E-1 lb/MMBtu.
                                    (1.5E0 lb/MWh)................                                                                                                 (2.0E0 lb/MWh).
Total non-mercury metals..........  5.0E-5 lb/MMBtu...............  6.0E-5 lb/MMBtu...............  8.0E-4 lb/MMBtu...............  6.0E-4 lb/MMBtu..............  4.0E-5 lb/MMBtu.
                                    (5.0E-1 lb/GWh)...............  (5.0E-1 lb/GWh)...............  (8.0E-3 lb/MWh) \a\...........  (7.0E-3 lb.MWh) \a\..........  (6.0E-1 lb/GWh).
Antimony, Sb......................  8.0E-1 lb/TBtu................  1.4E0 lb/TBtu.................  1.3E+1 lb/TBtu................  2.2E0 lb/TBtu................  8.0E-1 lb/TBtu.
                                    (8.0E-3 lb/GWh)...............  (2.0E-2 lb/GWh)...............  (2.0E-1 lb/GWh)...............  (2.0E-2 lb/GWh)..............  (8.0E-3 lb/GWh).
Arsenic, As.......................  1.1E0 lb/TBtu.................  1.5E0 lb/TBtu.................  2.8E0 lb/TBtu.................  4.3E0 lb/TBtu................  3.0E-1 lb/TBtu.
                                    (2.0E-2 lb/GWh)...............  (2.0E-2 lb/GWh)...............  (3.0E-2 lb/GWh)...............  (8.0E-2 lb/GWh)..............  (5.0E-3 lb/GWh).
Beryllium, Be.....................  2.0E-1 lb/TBtu................  1.0E-1 lb/TBtu................  2.0E-1 lb/TBtu................  6.0E-1 lb/TBtu...............  6.0E-2 lb/TBtu.
                                    (2.0E-3 lb/GWh)...............  (1.0E-3 lb/GWh)...............  (2.0E-3 lb/GWh)...............  (3.0E-3 lb/GWh)..............  (6.0E-4 lb/GWh).
Cadmium, Cd.......................  3.0E-1 lb/TBtu................  1.5E-1 lb/TBtu................  3.0E-1 lb/TBtu................  3.0E-1 lb/TBtu...............  3.0E-1 lb/TBtu.
                                    (3.0E-3 lb/GWh)...............  (2.0E-3 lb/GWh)...............  2.0E-3 lb/GWh)................  (3.0E-3 lb/GWh)..............  (4.0E-3 lb/GWh).
Chromium, Cr......................  2.8E0 lb/TBtu.................  2.9E0 lb/TBtu.................  5.5E0 lb/TBtu.................  3.1E+1 lb/TBtu...............  8.0E-1 lb/TBtu.
                                    (3.0E-2 lb/GWh)...............  (3.0E-2 lb/GWh)...............  (6.0E-2 lb/GWh)...............  (3.0E-1 lb/GWh)..............  (2.0E-2 lb/GWh).
Cobalt, Co........................  8.0E-1 lb/TBtu................  1.2E0 lb/TBtu.................  2.1E+1 lb/TBtu................  1.1E+2 lb/TBtu...............  1.1E0 lb/TBtu.
                                    (8.0E-3 lb/GWh)...............  (2.0E-2 lb/GWh)...............  (3.0E-1 lb/GWh)...............  (1.4E0 lb/GWh)...............  (2.0E-2 lb/GWh).
Lead, Pb..........................  1.2E0 lb/TBtu.................  1.9E+2 lb/MMBtu...............  8.1E0 lb/TBtu.................  4.9E0 lb/TBtu................  8.0E-1 lb/TBtu.
                                    (2.0E-2 lb/GWh)...............  (1.8E0 lb/MWh)................  (8.0E-2 lb/GWh)...............  (8.0E-2 lb/GWh)..............  (2.0E-2 lb/GWh).
Manganese, Mn.....................  4.0E0 lb/TBtu.................  2.5E0 lb/TBtu.................  2.2E+1 lb/TBtu................  2.0E+1 lb/TBtu...............  2.3E0 lb/TBtu.
                                    (5.0E-2 lb/GWh................  (3.0E-2 lb/GWh)...............  (3.0E-1 lb/GWh)...............  (3.0E-1 lb/GWh)..............  (4.0E-2 lb/GWh).
Mercury, Hg.......................  NA............................  NA............................  2.0E-1 lb/TBtu................  4.0E-2 lb/TBtu (4.0E-4 lb/     NA.
                                                                                                    (2.0E-3 lb/GWh)...............   GWh).
Nickel, Ni........................  3.5E0 lb/TBtu.................  6.5E0 lb/TBtu.................  1.1E+2 lb/TBtu................  4.7E+2 lb/TBtu...............  9.0E0 lb/TBtu.
                                    (4.0E-2 lb/GWh)...............  (7.0E-2 lb/GWh)...............  (1.1E0 lb/GWh)................  (4.1E0 lb/GWh)...............  (2.0E-1 lb/GWh).
Selenium, Se......................  5.0E0 lb/TBtu.................  2.2E+1 lb/TBtu................  3.3E0 lb/TBtu.................  9.8E0 lb/TBtu................  1.2E0 lb/TBtu.
                                    (6.0E-2 lb/GWh)...............  (3.0E-1 lb/GWh)...............  (4.0E-2 lb/GWh)...............  (2.0E-1 lb/GWh)..............  (2.0E-2 lb/GWh).
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
NA = Not applicable.
\a\ Includes Hg.


                                                            Table 6--Alternate Emission Limitations for New Coal- and Oil-Fired EGUs
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                    Liquid oil,  continental,  lb/  Liquid oil,  non-continental,
       Subcategory/Pollutant                Coal-fired EGUs                    IGCC \a\                           GWh                           lb/GWh                  Solid  oil- derived
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
SO2...............................  4.0E-1 lb/MWh.................  4.0E-1 lb/MWh.................  NA............................  NA...........................  4.0E-1 lb/MWh
Total non-mercury metals..........  6.0E-2 lb/GWh.................  4.0E-1 lb/GWh.................  2.0E-4 lb/MWh \b\.............  7.0E-3 lb/MWh \b\............  6.0E-1 lb/GWh
Antimony, Sb......................  8.0E-3 lb/GWh.................  2.0E-2 lb/GWh.................  1.0E-2........................  8.0E-3.......................  8.0E-3 lb/GWh
Arsenic, As.......................  3.0E-3 lb/GWh.................  2.0E-2 lb/GWh.................  3.0E-3........................  6.0E-2.......................  3.0E-3 lb/GWh
Beryllium, Be.....................  6.0E-4 lb/GWh.................  1.0E-3 lb/GWh.................  5.0E-4........................  2.0E-3.......................  6.0E-4 lb/GWh
Cadmium, Cd.......................  4.0E-4 lb/GWh.................  2.0E-3 lb/GWh.................  2.0E-4........................  2.0E-3.......................  7.0E-4 lb/GWh
Chromium, Cr......................  7.0E-3 lb/GWh.................  4.0E-2 lb/GWh.................  2.0E-2........................  2.0E-2.......................  6.0E-3 lb/GWh
Cobalt, Co........................  2.0E-3 lb/GWh.................  4.0E-3 lb/GWh.................  3.0E-2........................  3.0E-1.......................  2.0E-3 lb/GWh
Lead, Pb..........................  2.0E-3 lb/GWh.................  9.0E-3 lb/GWh.................  8.0E-3........................  3.0E-2.......................  2.0E-2 lb/GWh
Mercury, Hg.......................  NA............................  NA............................  1.0E-4........................  4.0E-4.......................  2.0E-3 lb/GWh
Manganese, Mn.....................  4.0E-3 lb/GWh.................  2.0E-2 lb/GWh.................  2.0E-2........................  1.0E-1.......................  7.0E-3 lb/GWh

[[Page 9369]]

 
Nickel, Ni........................  4.0E-2 lb/GWh.................  7.0E-2 lb/GWh.................  9.0E-2........................  4.1E0........................  4.0E-2 lb/GWh
Selenium, Se......................  6.0E-3 lb/GWh.................  3.0E-1 lb/GWh.................  2.0E-2........................  2.0E-2.......................  6.0E-3 lb/GWh
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
NA = Not applicable.
\a\ Based on best-performing similar source.
\b\ Includes Hg.

    As noted elsewhere in this preamble, we are finalizing a 
requirement to use filterable PM as a surrogate for the non-mercury 
metallic HAP and HCl as a surrogate for the acid gas HAP for all 
subcategories of coal-fired EGUs and for the solid oil derived fuel-
fired EGUs. For all liquid oil-fired EGUs, we are finalizing a 
requirement to use filterable PM as a surrogate for the total metallic 
HAP, and we are finalizing HCl and HF limits.
    In addition, we are finalizing alternative standards for certain 
HAP for some subcategories. The alternative pollutants and 
subcategories are as follows: (1) SO2 as a surrogate to HCl 
for all subcategories with add-on FGD systems (except liquid oil-fired 
subcategories as there were no existing units from which to base an 
alternate SO2 limit); (2) individual non-mercury metallic 
HAP as an alternate to filterable PM for all subcategories (except that 
it includes Hg for liquid oil-fired subcategories); and (3) total non-
mercury metallic HAP as an alternate to filterable PM for all 
subcategories (except that it includes Hg for liquid oil-fired 
subcategories). These alternative standards are discussed elsewhere in 
this preamble.
    We are finalizing a beyond-the-floor standard for Hg only for all 
existing coal-fired units designed for low rank virgin coal based on 
the use of activated carbon injection (ACI) for Hg control, as 
described elsewhere in this preamble. The EPA has determined that this 
beyond-the-floor level is achievable after considering the relevant CAA 
section 112(d)(2) provisions.
    As noted elsewhere in this preamble, we are also finalizing a 
compliance assurance option that would allow you to monitor liquid oil 
fuel moisture to demonstrate that fuel moisture content is no greater 
than 1.0 percent. Provided that demonstration is made, you will not 
have to conduct additional testing and monitoring to demonstrate 
compliance with the HCl and HF emission limits for units in both liquid 
oil subcategories (i.e., continental and non-continental).
    Pursuant to CAA section 112(h), we are finalizing a work practice 
standard for organic HAP, including emissions of dioxins and furans, 
for all subcategories of EGUs. The work practice standard being 
finalized requires the implementation of periodic burner tune-up 
procedures described elsewhere in this preamble. We are finalizing 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, even when long duration (around 8 hour) test 
runs are considered. As such, we consider it impracticable to measure 
emissions from these units. As discussed at proposal, we believe the 
inaccuracy of a majority of measurements, coupled with the extended 
sampling times used, allow a work practice standard under CAA section 
112(h) to apply to these HAP.\306\ We believe that a work practice 
standard will lead to a better environmental outcome than would be 
obtained through a requirement to measure a pollutant for which results 
may or may not be obtained. We believe that the work practice standard 
will result in actions being taken that will reduce emissions of these 
HAP.
---------------------------------------------------------------------------

    \306\ We would also note that the EPA, as a part of the 
Industrial Boiler MACT reconsideration proposal that was signed on 
December 2, 2011, is proposing to establish work practice standards 
for control of dioxins and furans from industrial boilers.
---------------------------------------------------------------------------

    In addition, as discussed below, we are creating a subcategory for 
limited use liquid oil-fired electric utility steam generating unit 
with an annual capacity factor of less than 8 percent of its maximum or 
nameplate heat input and we are establishing work practice standards 
applicable to such units pursuant to CAA section 112(h).
    We are finalizing that new or existing EGUs are ``coal-fired'' if 
they combust coal more than 10 percent of the average annual heat input 
during any 3 consecutive calendar years or for more than 15 percent of 
the annual heat input during any one calendar year and meet the final 
definition of ``fossil fuel-fired.'' We are finalizing that an EGU is 
considered to be in the coal-fired ``unit designed for coal greater 
than or equal to 8,300 Btu/lb'' subcategory if the EGU: (1) meets the 
final definitions of ``fossil fuel-fired'' and ``coal-fired electric 
utility steam generating unit;'' and (2) is not a coal-fired EGU in the 
``unit designed for low rank virgin coal'' subcategory.
    We are finalizing that the EGU is considered to be in the ``unit 
designed for low rank virgin coal'' subcategory if the EGU: (1) meets 
the final definitions of ``fossil fuel-fired'' and ``coal-fired 
electric utility steam generating unit;'' and (2) is designed to burn 
and is burning nonagglomerating virgin coal having a calorific value 
(moist, mineral matter-free basis) of less than 19,305 kJ/kg (8,300 
Btu/lb) and that is constructed and operates at or near the mine that 
produces such coal.\307\
---------------------------------------------------------------------------

    \307\ ASTM Method D388-05, ``Standard Classification of Coals by 
Rank'' (incorporated by reference, see Sec.  63.14).
---------------------------------------------------------------------------

    We are finalizing that the EGU is considered to be an IGCC unit if 
the EGU: (1) Combusts a synthetic gas derived from gasified coal or 
solid oil-derived fuel (e.g., petroleum coke, pet coke), (2) meets the 
final definition of ``fossil fuel-fired,'' and (3) is classified as an 
IGCC unit. We are not subcategorizing IGCC EGUs based on the source of 
the syngas used (e.g., coal, petroleum coke). Based on information 
available to the Agency, although the fuel characteristics of coal and 
petcoke are quite different, the syngas products from both feedstocks 
have similar HAP content and similar HAP emissions characteristics that 
can be controlled in a similar manner.\308\
---------------------------------------------------------------------------

    \308\ U.S. Department of Energy, Wabash River Coal Gaification 
Repowering Project. Project Performance Summary; Clean Coal 
Technology Demonstration Program. DOE/FE-0448. July 2002. EPA-HQ-
OAR-2009-0234-2933.
---------------------------------------------------------------------------

    We are finalizing that the EGU is considered to be in the 
``Continental liquid oil-fired'' subcategory if (1) meets the final 
definitions of ``oil-fired electric utility steam generating unit'' and 
``fossil fuel-fired;'' and (2) is located in the continental United 
States (U.S.).
    We are finalizing that the EGU is considered to be ``Non-
continental liquid oil-fired'' subcategory if (1) meets the final 
definitions of ``oil-fired electric utility steam generating unit'' and

[[Page 9370]]

``fossil fuel-fired;'' and (2) is located outside continental U.S.
    We are finalizing that the EGU is considered to be ``solid oil-
derived fuel-fired'' if (1) the EGU is not a coal-fired EGU and burns 
solid oil-derived fuel (e.g., petroleum coke, pet coke); and (2) meets 
the final definitions of ``oil-fired electric utility steam generating 
unit'' and ``fossil fuel-fired.''
    We are finalizing that the EGU is considered to be a ``limited-use 
liquid oil-fired'' if (1) the EGU meets the final definitions of ``oil-
fired electric utility steam generating unit'' and ``fossil fuel-
fired;'' and (2) has an annual capacity factor of less than 8 percent 
of its maximum or nameplate heat input, whichever is greater, averaged 
over a 24-month block contiguous period commencing.

E. What are the requirements during periods of startup, shutdown, and 
malfunction?

    As discussed below in section VI.E., for startup and shutdown, the 
requirements have changed since proposal. For periods of startup and 
shutdown, the EPA is finalizing work practice standards in lieu of 
numeric emission limits. Numeric emission limits apply for all other 
periods for all pollutants, except organic HAP. For malfunctions, the 
EPA is finalizing an affirmative defense for exceedances of the 
numerical emission limits that are caused by malfunctions.

F. What are the testing and initial compliance requirements?

    We are requiring that you, as an owner or operator of a new or 
existing coal- or oil-fired EGU, must conduct performance tests to 
demonstrate compliance with all applicable emission limits. For units 
using certified continuous emissions monitoring systems (CEMS) that 
directly measure the regulated pollutant under final 40 CFR part 63, 
subpart UUUUU (e.g., Hg CEMS, HCl CEMS, HF CEMS, SO2 CEMS 
(where an SO2 limit applies as the alternative equivalent 
standard)), or sorbent trap monitoring systems, the initial performance 
test consists of all valid data recorded with the certified monitoring 
system in the first 30 boiler operating days of data collected with the 
certified monitoring system prior to the initial compliance 
demonstration date specified in Sec.  63.10005. A source may also elect 
to use a PM CEMS to demonstrate compliance with the filterable PM 
emission limit. If this option is selected, then the same provisions as 
noted above for other CEMS will apply. (Note that EPA anticipates that 
the PM monitoring device that may most often will be used is a PM 
continuous parameter monitoring system (CPMS) in conjunction with an 
operating limit, as more fully described below.) For units and 
pollutants not being monitored via CEMS, the owner or operator of an 
affected unit must perform the initial performance testing in 
accordance with established EPA reference test methods or the voluntary 
consensus standard methods incorporated by reference. You, as the owner 
or operator of an affected unit, must conduct the following compliance 
tests where applicable:
    (1) For coal-fired units, IGCC units, and solid oil-derived fuel-
fired units, if you elect to comply with the filterable PM emission 
limit, you must conduct filterable PM emissions testing using EPA 
Method 5 from Appendix A to part 60 of chapter 40 to determine initial 
compliance. Alternatively, if you elect to comply with the total non-
mercury HAP metals emission limit or the individual non-mercury HAP 
metals emissions limits, you must conduct HAP metals testing using EPA 
Method 29 from Appendix A to part 60 of chapter 40. Note for this rule 
that the filter temperature for each Method 5 or 29 emissions test must 
be maintained at 160[deg]  14 [deg]C (320 [deg]  25 [deg]F), and the material in Method 29 impingers must be 
analyzed for metals content. Whenever metals testing is performed with 
Method 29, you must report the front half and back half analytical 
fractions separately.
    (2) For coal-fired, IGCC, and solid oil-derived fuel-fired units, 
you must use a Hg CEMS or a sorbent trap monitoring system for both 
initial compliance and continuous compliance using the continuous Hg 
monitoring provisions of Appendix A to 40 CFR part 63, subpart UUUUU, 
except where the low emitting EGU (LEE) requirements apply (see below). 
The initial performance test consists of all valid data recorded with 
the certified Hg monitoring system in the 30 boiler operating days of 
data collected with the certified monitoring system by the initial 
compliance demonstration date specified in Sec.  63.10005.
    (3) For coal-fired and solid oil-derived fuel-fired units and new 
or reconstructed IGCC units that employ FGD technology and elect to 
meet the alternative SO2 limit in place of the HCl limit, 
you need not conduct an initial stack test for HCl or SO2. 
Instead, the 30 boiler operating days of data collected with the 
certified SO2 CEMS by the initial compliance demonstration 
date specified in Sec.  63.10005 are used to determine initial 
compliance, and the SO2 CEMS is used thereafter to 
demonstrate continuous compliance. If you instead opt to meet the HCl 
limit and use an HCl CEMS for compliance, you need not conduct an 
initial stack test for HCl. Instead, the 30 boiler operating days of 
data collected with the certified HCl CEMS by the initial compliance 
demonstration date specified in Sec.  63.10005 are used to determine 
initial compliance. For units not using the SO2 or HCl CEMS 
options, you must conduct an initial stack test for HCl using EPA 
Method 26, 26A, or 320 from Appendix A to part 60 of chapter 40. You 
may use EPA Method 26 or 320 or ASTM Method D6348-03 (Reapproved 2010) 
with additional quality assurance if no entrained water droplets exist 
in the exhaust gas, but you must use Method 26A if entrained water 
droplets exist in the exhaust gas.
    (4) For liquid oil-fired units, you must conduct initial 
performance testing as follows. If you elect to meet the filterable PM 
limit instead of the non-mercury metals limit (total or individual), 
then use Method 5 with the filter material maintained at 160[deg] 
 14[deg]C (320[deg]  25[deg]F). Alternatively, 
you may use a PM CEMS as discussed elsewhere in this preamble. If you 
elect to meet either the total or individual HAP metals limit, you will 
use Method 29 for all non-mercury HAP metals. For Hg, conduct emissions 
testing using EPA Method 29 or 30B from Appendix A to part 60 of 
chapter 40, or ASTM Method D6784-02 (Reapproved 2008). For acid gases, 
conduct HCl and HF testing using EPA Method 26A, 320, or 26; or you may 
elect to comply by using an HCl CEMS and/or an HF CEMS; or under 
certain conditions you may choose to demonstrate compliance by 
measuring fuel moisture to demonstrate that moisture content is no 
greater than 1.0 percent. You must measure daily if fuel is delivered 
continuously or per shipment if fuel is delivered on a batch basis, or 
you may use a fuel moisture content certification provided by your fuel 
supplier. If you use a CEMS, then use the 30 boiler operating days of 
data collected with the certified monitoring system by the initial 
compliance demonstration date specified in Sec.  63.10005 to determine 
initial compliance.
    (5) For the required performance stack tests, if you are 
demonstrating compliance with a heat-input based standard, you must 
conduct concurrent O2 or carbon dioxide (CO2) 
emission testing using EPA Method 3A or 3B from appendix A to part 60 
of chapter 40 or ANSI/ASME PTC 19.10-1981 and then use an appropriate 
equation, selected from among Equations 19-1

[[Page 9371]]

through 19-9 in EPA Method 19 from appendix A to part 60 of chapter 40, 
to convert measured pollutant concentrations to lb/MMBtu values. 
Multiply the lb/MMBtu value by one million to get the lb/TBtu value 
(where applicable). If you choose to meet an electrical output-based 
emissions limit, you must also collect concurrent stack gas flow rate 
and electrical production data.
    (6) For an existing unit that you believe will qualify as LEE for 
Hg, you must conduct an initial Method 30B test over 30 days and follow 
the calculation procedures in the final rule to document a potential to 
emit less than 10 percent of the applicable Hg emissions limit or less 
than 29 pounds of Hg per year. If your unit qualifies as a LEE for Hg, 
you must conduct subsequent performance tests on an annual basis to 
demonstrate that the unit continues to qualify. For all other 
pollutants, you must conduct the initial compliance test, and then all 
other required tests over a 3-year period, and in all such tests, your 
emission results must be less than 50 percent of the applicable 
emission limit. If you qualify as a LEE on that basis, you must conduct 
subsequent performance tests every 3 years to demonstrate that the unit 
continues to qualify.
    (7) You may use results from tests conducted no earlier than 12 
months before the compliance date of this rule as the initial 
performance test for an applicable pollutant, provided that:
    a. You certify and keep records demonstrating that no significant 
changes have occurred,
    b. Tests were conducted using methods allowed in this rule in 
accordance with Sec.  63.10007 and Table 5,
    c. You have records of all parameters needed to convert results to 
units of the standard for the entire period, and
    d. For a CEMS-based performance test, you have all the required 
data for the entire 30-boiler operating day rolling average period.
Operating Limit for PM CEMS
    Under the final rule, you may elect to comply continuously with an 
operating limit, established during the initial performance test, to 
demonstrate continuous compliance with the filterable PM, total non-
mercury HAP metals, or individual non-mercury HAP metals limit. You 
will use a PM CPMS to monitor compliance with the operating limit. The 
PM CPMS operating principle must be based on in-stack or extractive 
light scatter, light scintillation, beta attenuation, or mass 
accumulation detection of the exhaust gas or representative exhaust gas 
sample. The reportable measurement output from the PM CPMS may be 
expressed as milliamps, stack concentration, or other raw data signal. 
Meeting the operating limit serves as your demonstration of continuous 
compliance with the filterable PM, total non-mercury HAP metals, or 
individual non-mercury HAP metals limit. As mentioned earlier, if you 
use this method to demonstrate continuous compliance, you must install 
a PM CPMS and establish the operating limit during the initial 
compliance test for filterable PM, total non-mercury HAP metals, or 
individual non-mercury HAP metals. As noted below, when you use this 
operating limit, you can reduce stack testing frequency to demonstrate 
ongoing compliance. You may also opt to install and operate a PM CEMS 
certified in accordance with Performance Specification 11 and Procedure 
2 of 40 CFR part 60, Appendices B and F, respectively. If you elect to 
use this option, then the requirements for quarterly testing with 
Method 5, or annual testing and use of a PM CPMS, are no longer 
applicable.
Dioxins/Furans and Non-Dioxin/Furan Organic HAP
    For dioxins and furans and non-dioxin/furan organic HAP, you must 
submit documentation that you have conducted a combustion process tune-
up, a thorough equipment inspection, and an optimization to minimize 
generation of CO and NOX, all meeting the requirements of 
this final rule. The work practice standard involves maintaining and 
inspecting the burners and associated combustion controls, tuning the 
specific burner type to optimize combustion, obtaining and recording CO 
and NOX values before and after burner adjustments, keeping 
records of activity and measurements, and submitting a report for each 
tune-up conducted. You must collect CO and NOX data and may 
use portable analyzers (which include handheld or similar devices) to 
monitor and verify the results. The specific details are addressed in 
40 CFR 63.10021 of the final rule.
    This same work practice standard also applies in place of any 
emission limits for Hg, non-mercury metals HAP, acid gas HAP, dioxins 
and furans, and non-dioxin/furan organic HAP from a limited-use, liquid 
oil-fired EGU (i.e., a unit that has an annual capacity factor on oil 
of less than 8 percent of its maximum or nameplate heat input, 
whichever is greater). The EPA established this subcategory in response 
to comments and a further analysis of the units within this subcategory 
in the ICR database. For these units, EPA believes that the required 
work practice standards are appropriate and consistent with the 
requirement of CAA section 112(h).

G. What are the continuous compliance requirements?

    To demonstrate continuous compliance with the emission limitations, 
the final rule includes the following requirements:
    (1) Use of CEMS. Where a CEMS or a sorbent trap monitoring system 
is used for demonstrating initial compliance, you also must use the 
CEMS or sorbent trap monitoring system on a continuous basis to 
demonstrate ongoing compliance with the numerical emission limits. CEMS 
or sorbent trap monitoring system data are not used to determine 
compliance with the work practice standards applicable during periods 
of startup and shutdown, but sources that install a CEMS or a sorbent 
trap monitoring system to demonstrate compliance with the numerical 
emission limits must operate the system at all times, as EPA intends to 
evaluate the continuous monitoring data from start-up and shutdown 
periods as discussed below. You must calculate a rolling average for 
each successive 30-boiler operating day rolling average period. All 
valid data collected during each successive period will be used to 
demonstrate compliance, except for data collected during periods of 
startup and shutdown; during those periods, the owner or operator must 
meet work practice requirements instead of the numerical emission 
limits. There is no numerical minimum data availability required to 
constitute a valid 30-boiler operating day rolling average; however, 
you must monitor at all times that the process is in operation 
(including during startups and shutdowns, although emissions during 
these periods are not included in the 30-boiler operating day average). 
You must operate, maintain, and quality-assure the CEMS or sorbent trap 
monitoring systems in accordance with the provisions in 40 CFR 63.10010 
and Appendix A and B of the final rule (for Hg, HCl, and HF CEMS), in 
accordance with Performance Specification 11 in Appendix B to 40 CFR 
part 60 and Procedure 2 in Appendix F to part 60 (for PM CEMS used for 
direct compliance), or in accordance with 40 CFR part 75 (for 
SO2 CEMS, and certain ancillary monitors such as a diluent 
or moisture monitor).
    For each unit using HCl, HF, SO2, PM, or Hg CEMS or a 
sorbent trap monitoring system for continuous compliance, you must 
install, certify, maintain, operate and quality-assure the

[[Page 9372]]

additional CEMS (e.g., CEMS that measure O2 or 
CO2 concentration, stack gas flow rate, and, if default 
moisture values are not used, moisture content) needed to convert 
pollutant concentrations to units of the emission standards or 
operating limits. Where appropriate, you must certify and quality-
assure these additional CEMS according to 40 CFR part 75.
    For HCl and HF CEMS, the EPA is adding monitoring provisions as 
Appendix B to 40 CFR part 63, subpart UUUUU. Appendix A references 
performance specification (PS) 15 of Appendix B to 40 CFR part 60 for 
Fourier Transform Infrared (FTIR) CEMS for procedures to certify and 
conduct ongoing quality assurance on these FTIR CEMS. In addition, we 
expect to publish a PS specific to HCl CEMS in the near future (prior 
to the compliance date of this rule). In the meantime, you may petition 
the Administrator under the procedure given in 40 CFR 63.7(f) for an 
alternative approach to compliance monitoring or testing for HCl or any 
other regulated pollutant.
    When using a sorbent trap monitoring system, you may use each pair 
of sorbent traps to collect Hg samples for no more than 15 boiler 
operating days. Under the general duty to monitor at all times, you 
must replace traps in a timely manner to ensure that Hg emissions are 
sampled continuously.
    For Hg monitoring, the EPA is adding Hg monitoring provisions as 
Appendix A to 40 CFR part 63, subpart UUUUU, and requiring use of these 
provisions to document continuous compliance with the rule for coal-
fired, IGCC, and solid oil derived-fired units that cannot qualify as 
LEEs. Appendix A consolidates all Hg monitoring provisions.
    Today's rule provides two basic Hg continuous monitoring options: 
Hg CEMS and sorbent trap monitoring systems. Appendix A requires 
initial certification and periodic quality assurance (QA) testing of 
the Hg CEMS and sorbent trap monitoring systems. The certification 
tests required for the Hg CEMS are a 7-day calibration error test; a 
linearity check, using NIST-traceable elemental Hg standards; a 3-level 
system integrity check (similar to a linearity check), using NIST-
traceable oxidized Hg standards; a cycle time test; and a relative 
accuracy test audit (RATA). Table A-1 of Appendix A summarizes the 
performance specifications for the required certification tests. For 
ongoing QA of the Hg CEMS, Appendix A requires daily calibrations, 
weekly single-point system integrity checks, quarterly linearity checks 
(or 3-level system integrity checks), and annual RATAs. Table A-2 in 
Appendix A summarizes these ongoing QA test requirements and the 
applicable performance criteria for Hg CEMS, which are consistent with 
those published in support of CAMR and are, thus, familiar to the 
industry.
    For sorbent trap monitoring systems, a RATA is required for initial 
certification, and annual RATAs are required for ongoing QA. The 
performance specification for these RATAs is the same as for the RATAs 
of the Hg CEMS. Bias adjustment of the measured Hg concentration data 
is not required. For day-to-day operation of the sorbent trap system, 
Appendix A requires you to follow the procedures and QA/QC criteria in 
PS 12B in Appendix B to 40 CFR part 60. PS 12B is nearly identical to 
the Appendix K to 40 CFR part 75, published in support of CAMR and with 
which the industry is familiar. The 40 CFR part 75 concepts of:
    a. Determining the due dates for certain QA tests on the basis of 
``QA operating quarters'' and
    b. Grace periods for certain QA tests apply to both Hg CEMS and 
sorbent trap monitoring systems. Mercury concentrations measured by Hg 
CEMS or sorbent trap systems are used together with hourly flow rate, 
diluent gas, moisture, and electrical load data, to express the Hg 
emissions in units of the rule, on an hourly basis (i.e., lb/TBtu or 
lb/GWh). Section 6 of Appendix A provides the necessary equations for 
these unit conversions.
    For HCl and HF CEMS, the EPA is adding monitoring provisions as 
Appendix B to 40 CFR part 63, Subpart UUUUU. Appendix A references 
performance specification (PS) 15 of Appendix B to 40 CFR part 60 for 
Fourier Transform Infrared (FTIR) CEMS for procedures to certify and 
conduct ongoing quality assurance on these FTIR CEMS. In addition, we 
expect to promulgate a generic PS specific to HCl CEMS prior to the 
compliance date of this rule. In the meantime, you may petition the 
Administrator under the procedure given in 40 CFR 63.7(f) for an 
alternative approach to compliance monitoring or testing for HCl or any 
other regulated pollutant.
    (2) Use of stack tests. If you demonstrate initial compliance on 
the basis of a stack test, you must demonstrate continuous compliance 
by conducting periodic stack tests on a quarterly basis. This includes 
filterable PM (or non-mercury HAP metals) and HCl from coal-fired and 
solid oil-derived fuel-fired EGUs, and filterable PM (or HAP metals) 
and HCl and HF from liquid oil-fired EGUs with the following 
exceptions:
    a. If you use a PM CPMS and associated operating limit, you may 
conduct the applicable Method 5 or Method 29 test once annually rather 
than quarterly, in which case you must re-establish the operating limit 
during each performance test. A PM CPMS does not need to meet the 
requirements for a PM CEMS under PS 11. The final rule includes basic 
quality checks that the PM CPMS must meet and a requirement for you to 
develop and follow a site-specific monitoring plan to be approved by 
the delegated authority. You must demonstrate compliance with the 
operating limit by using all valid hourly data collected during each 
successive 30-boiler operating day period rolled daily. The 30-boiler 
operating day rolling average is calculated by all of the valid hourly 
average PM CPMS output values collected for the 30 boiler operating 
days (excluding hours of startup and shutdown; see section V.E. of this 
preamble).
    b. If you combust liquid fuels and if your fuel moisture content is 
no greater than 1.0 percent, you may demonstrate ongoing compliance 
with HCl and HF emissions limits by:
    i. Measuring fuel moisture content of each shipment of fuel if your 
fuel arrives on a batch basis;
    ii. Measuring fuel moisture content daily if your fuel arrives on a 
continuous basis; or
    iii. Obtaining and maintaining a fuel moisture certification from 
your fuel supplier.
    Should the moisture in your liquid fuel be more than 1.0 percent, 
you must
    i. Conduct HCl and HF emissions testing quarterly and establish 
site-specific monitoring to demonstrate continued acid gas control 
performance between periodic tests, or
    ii. Use an HCl CEMS and/or HF CEMS.
    c. If your existing unit qualifies as an LEE for Hg, you must 
conduct another 30-day Method 30B performance test on your unit once 
per year to reestablish that the unit continues to qualify as a LEE for 
Hg. If the results of the LEE test show that the unit exceeds 10 
percent of the emissions limit or exceeds the potential to emit 29 
pounds of Hg per year, you will lose LEE status for the unit. You can 
regain LEE status for that unit if every required performance test for 
a 3-year period shows that emissions from the unit did not exceed the 
LEE limit. If LEE status is lost for a solid fuel unit, you must 
commence quarterly performance testing until you install,

[[Page 9373]]

certify, and operate a Hg CEMS or a sorbent trap monitoring system, and 
you must complete the installation and certification within 6 months of 
losing LEE status; for a liquid fuel unit, you must commence quarterly 
performance testing.
    d. If a liquid oil-fired EGU has an annual capacity factor on oil 
of less than 8 percent of its maximum or nameplate heat input, 
whichever is greater, you must demonstrate continuous compliance with 
the applicable work practice standard by conducting at least once every 
36 calendar months (48 calendar months if a neural network is employed) 
a combustion process tune-up, a thorough equipment inspection, and an 
optimization to minimize generation of CO and NOX, all 
meeting the requirements of this final rule. You must maintain and 
inspect the burners and associated combustion controls, tuning the 
specific burner type to optimize combustion, obtaining and recording CO 
and NOX values before and after burner adjustments, keeping 
records of activity and measurements, and submitting a report for each 
tune-up conducted. You must collect CO and NOX data using 
portable analyzers (which typically include handheld or similar 
devices). Specific details are addressed in 40 CFR 63.10021 of the 
final rule. In addition, you must record boiler operating hours, by 
fuel type, in each calendar quarter.
    e. The rule allows a grant of LEE status to existing units with 
test results that show a history of low, non-mercury emissions. As 
mentioned earlier, LEE status reduces testing frequency for units. 
After a 3-year period during which every emissions test for a specific 
pollutant shows emissions no greater than 50 percent of the emissions 
limit, you may reduce the emissions testing frequency for that specific 
non-mercury pollutant to once every 36 months. If any subsequent 
emissions test for that pollutant exhibits emissions greater than 50 
percent of the emissions limit, you must revert to the original 
emissions testing frequency until you re-establish a 3-year period of 
very low emissions no greater than 50 percent of the standard.
    f. For liquid oil-fired units that demonstrate continuous 
compliance with quarterly performance tests for HCl and HF emission 
limits rather than through use of HCl and HF CEMS, the final rule 
requires a site-specific monitoring plan in addition to the quarterly 
tests. For these pollutants, there is unlikely to be any existing 
underlying monitoring (such as compliance assurance monitoring) that 
serves as an additional tool to ensure the source's operations remain 
consistent with operating conditions during a recent successful 
performance test. The requirement for a site-specific monitoring plan 
fills this gap and ensures that in between tests, the source continues 
to operate in a manner designed to maintain HCl and HF emissions in 
compliance with the emission limits under this rule. The appropriate 
parameters to monitor will depend on the compliance strategy employed 
by a specific source, and thus EPA is enabling the monitoring approach 
to be established on a case-by-case basis. Given the relatively small 
number of these units and the other compliance options available, we 
anticipate that this approach will apply to a small set of units. The 
monitoring plan will identify the parameters monitored, the monitoring 
methods, the QA/QC elements that apply, and the data reduction elements 
(including appropriate averaging periods, as applicable). See 40 CFR 
63.10000(c)(2)(ii).
    (3) Work practice standard. For the performance tune-up work 
practice requirements, you must demonstrate continuous compliance by 
conducting the work practice at least once every 36 calendar months (48 
calendar months if a neural network is employed). The work practice 
involves maintaining and inspecting the burners and associated 
combustion controls, tuning the specific burner type, as applicable, to 
optimize combustion, obtaining and recording CO and NOX 
values before and after burner adjustments, keeping records of activity 
and measurements, and submitting a report for each tune-up conducted. A 
combustion tune-up will involve optimizing combustion of the unit 
consistent with manufacturer's instruction as applicable, or in 
accordance with best combustion engineering practice for that burner 
type.

H. What are the notification, recordkeeping and reporting requirements?

    All new and existing sources in all subcategories must comply with 
certain requirements of the General Provisions (40 CFR part 63, subpart 
A), which are identified in Table 9 of this final rule. The General 
Provisions include specific requirements for notifications, 
recordkeeping, and reporting. You must submit a notification of 
compliance status report for each unit, according to the schedule 
required by 40 CFR 63.9(h) of the General Provisions, including a 
certification of compliance.
    Except for units that use CEMS for continuous compliance, under 
this rule you must provide semiannual compliance reports, as required 
by 40 CFR 63.10(e)(3) of subpart A, that indicate whether a deviation 
from any of the requirements in the rule occurred and whether or not 
any process changes occurred and compliance certifications were 
reevaluated. As discussed below, we are finalizing a requirement to use 
the 40 CFR part 75-based Emissions Collection and Monitoring Plan 
System (ECMPS) for reporting emissions and related data for units using 
CEMS for most pollutants. Also, as discussed below, for the PM CPMS, PM 
CEMS, and performance test results, we require you to use EPA's WebFIRE 
\309\ database for reporting.
---------------------------------------------------------------------------

    \309\ WebFIRE is the Internet version of FIRE. The Factor 
Information Retrieval (FIRE) Data System is a database management 
system containing EPA's recommended emission estimation factors for 
criteria and HAP. It includes information about industries and their 
emitting processes, the chemicals emitted, and the emission factors 
themselves.
---------------------------------------------------------------------------

    This rule requires you to keep certain records to demonstrate 
compliance with each emission limit and work practice standard. The 
General Provisions to 40 CFR part 63 specify these recordkeeping 
requirements (see Table 9 to this subpart). Among other specific 
records, you must keep the following:
    (1) All reports and notifications submitted to comply with this 
rule.
    (2) Continuous monitoring data as required in this rule.
    (3) Each instance in which you did not meet an emission limit, work 
practice requirement, operating limit, or other compliance obligation 
(i.e., deviations from this rule).
    (4) Daily hours of operation by each unit.
    (5) As part of the general duty to keep all monitoring data, fuel 
moisture content of liquid fuel, if you elect to demonstrate compliance 
using that information.
    (6) A copy of the results of all performance tests, monitor 
certifications, performance evaluations, or other compliance 
demonstrations conducted to demonstrate initial or continuous 
compliance with this rule.
    (7) A copy of your site-specific performance evaluation test plans 
developed for this rule as specified in 40 CFR 63.8(e), if applicable.
    (8) A copy of your acid gas control system parameter monitoring 
plan under 40 CFR 63.10000(c)(2)(ii).
    You also must submit the following additional notifications:
    (1) Notifications required by the General Provisions.
    (2) Initial Notification no later than 120 calendar days after you 
become subject to this subpart.

[[Page 9374]]

    (3) Notification of Intent to conduct performance tests and/or 
compliance demonstration at least 60 calendar days before the 
performance test and/or compliance demonstration is scheduled.
    (4) Notification of Compliance Status 60 calendar days following 
completion of the performance test and/or compliance demonstration.
    Electronic reporting is becoming a common element of modern life 
(as evidenced by electronic banking and income tax filing), and the EPA 
is beginning to require electronic submittal of environmental data. 
Electronic reporting is already common in environmental data collection 
and many media offices at EPA are reducing reporting burden for the 
regulated community by embracing electronic reporting systems as an 
alternative to paper-based reporting.
    One of the major benefits of reporting electronically is 
standardization, to the extent possible, of the data reporting formats 
that provides more certainty to users of what data are required in 
specific reports. For example, electronic reporting software allows for 
more efficient data submittal and the software's validation mechanism 
helps industry users submit fewer incomplete reports. This alone saves 
industry report processing resources and reduces transaction times. 
Standardization also allows for development of efficient methods to 
compile and store much of the documentation required to be reported by 
this rule.
Use of Electronic Reporting System
    We are requiring that you submit certain reports electronically. In 
addition to supporting regulation development, control strategy 
development, and other air pollution control activities, having an 
electronic database populated with these reports will save industry, 
state, local, tribal agencies, the public, and the EPA significant 
time, money, and effort while also improving the transparency and 
quality of emission inventories and, as a result, air quality 
regulations.
    The reports to be submitted electronically include all performance 
test reports, notification of compliance status reports, compliance, 
and continuous monitoring data summaries specified in 40 CFR 63.10031 
of this rule. Performance tests are required to be conducted as 
described in 40 CFR 63.7 of the General Provisions. The data that must 
be submitted as the performance test report are also described in 40 
CFR 63.7. These data must be submitted (except in limited cases) to 
EPA's WebFIRE database by using the electronic reporting tool (ERT) and 
the Compliance and Emissions Data Reporting Interface (CEDRI) that is 
accessed through EPA's Central Data Exchange (CDX), as described below. 
The data requirements for the notification of compliance status and 
compliance reports are described in detail in the regulatory text (40 
CFR 63.10031) of this rule, but they essentially mirror the 
requirements in 40 CFR 63.6 of the General Provisions. These reports 
will also be submitted to WebFIRE using an electronic form found in 
CEDRI and through the CDX as described below. As required in 40 CFR 
63.10031(f)(2) of the final rule, the continuous monitoring summaries 
are required to be submitted quarterly. The quarterly reports must 
include all of the calculated 30-boiler operating day rolling average 
values derived from the PM CPMS. These reports will also be submitted 
to WebFIRE using an electronic form found in CEDRI and through the CDX, 
as described below. This same approach will apply if a source elects to 
use a PM CEMS or receives approval to use a HAP metals CEMS as an 
alternative monitoring method.
    The availability of electronic reporting for sources subject to the 
Subpart UUUUU will provide efficiency, improved services, better 
accessibility of information, and more transparency and accountability. 
Additionally, submittal of these required reports electronically 
provides significant benefits for regulatory agencies, industry, and 
the public. The compliance data electronic reporting system (CEDRI and 
CDX) is being developed such that once a facility's initial data entry 
into the system is established and a report is generated, subsequent 
data submittal will only consist of electronic updates to existing 
information in the system. Such a system will effectively reduce the 
burden associated with submittal of data and reports by reducing the 
time, costs, and effort required to submit and update hard copies of 
documentation. State, local, and tribal air pollution control agencies 
will also benefit from having access to the more streamlined and 
accurate electronic data submitted to the EPA. Electronic reporting 
will allow for an electronic review process rather than a manual data 
assessment, making review and evaluation of the source-provided data 
and calculations easier and more efficient. Electronic reporting will 
also benefit the public by generating a more transparent review process 
and increasing the ease and efficiency of data accessibility. 
Furthermore, electronic reporting will reduce the burden on the 
regulated community by reducing the effort involved in data collection 
and reporting activities. In the future, we anticipate there will be 
fewer and less substantial data collection requests in conjunction with 
prospective required residual risk assessments or technology reviews. 
Electronic reporting will substantially reduce this burden, because the 
EPA will already have these data available and consolidated in an 
electronic database named WebFIRE. We anticipate that using electronic 
reporting for the required reports will result in an overall reduction 
in reporting costs; for a discussion of the economic and cost impacts 
of electronic reporting, see section XII.D. of this preamble.
    Another benefit of electronic data submittal is that these data 
will greatly improve the overall quality of existing and new emissions 
factors by supplementing the pool of emissions test data for 
establishing emissions factors and by ensuring that the factors are 
more representative of current industry operational procedures. A 
common complaint heard from industry and regulators is that emission 
factors are outdated or not representative of a particular source 
category. With timely receipt and incorporation of data from most 
performance tests, the EPA will be able to ensure that emission 
factors, when updated, represent the most current range of operational 
practices.
    Data entry of these electronic reports will be through the CEDRI 
that is accessed through EPA's CDX (www.epa.gov/cdx). Data submitted 
electronically through CEDRI will be stored in CDX as an official copy 
of record.
    Once you have accessed CEDRI, you will select the applicable 
subpart for the report that you are submitting. You will then select 
the report being submitted, enter the data into the form, and click on 
the submit button. In some cases, such as with submittal of a 
notification of compliance status report, you will select the report 
icon, enter basic facility information, and then upload the report in a 
specified file format.
    In addition, we believe that there will be value in allowing other 
reporting forms to be developed and used in cases where the other 
reporting forms can provide an alternate electronic file consistent 
with EPA's form output format. This approach has been used successfully 
to provide alternatives for other electronic forms (e.g., income tax 
submittal).
    In cases where performance test data are to be submitted to the 
EPA, you must enter the performance test data

[[Page 9375]]

and information into the electronic reporting tool (ERT) which can be 
accessed at http://www.epa.gov/ttn/chief/ert/index.html. In CEDRI, the 
user must then upload the ERT file. CEDRI submits a copy of the ERT 
project data file directly to WebFIRE where the data are made 
available. Where performance test reports are submitted, WebFIRE 
notifies the appropriate state, local, or tribal agency contact that an 
ERT project data file was received from the source.
    Submitting performance test data electronically to the EPA will 
apply only to those performance tests conducted using test methods that 
will be supported by the ERT. The ERT contains a specific electronic 
data entry form for most of the commonly used EPA reference methods. A 
listing of the pollutants and test methods supported by the ERT is 
available at the ERT Web site listed above.

I. Submission of Emissions Test Results to the EPA

    The EPA has determined that harmonization of the monitoring and 
reporting requirements of this final rule with 40 CFR part 75 is 
appropriate, where the affected industry already has a well-defined 
system for continuous monitoring and reporting of emissions under that 
part. Therefore, the Agency is finalizing monitoring and reporting 
requirements for most CEMS that are consistent with 40 CFR part 75. You 
must report CEMS data (other than PM CEMS data or data from alternative 
monitoring subject to site-specific approval such as a HAP metals CEMS) 
to the EPA electronically, on a quarterly basis, using the ECMPS.
    The ECMPS process divides electronic data into three categories, 
the first of which is monitoring plan data. You must maintain the 
electronic monitoring plan separately and can update it at any time if 
necessary. The monitoring plan documents the characteristics of the 
affected units (e.g., unit type, rated heat input capacity, etc.) and 
the monitoring methodology used for each parameter (e.g., CEMS). The 
monitoring plan also describes the type of monitoring equipment used 
(hardware and software components), includes analyzer span and range 
settings, and provides other useful information. Nearly all coal-fired 
EGUs are subject to the ARP and thus have established electronic 
monitoring plans that describe their required SO2, flow 
rate, CO2 or O2, and, in some cases, moisture 
monitoring systems. The EPA will adjust the ECMPS monitoring plan 
format to accommodate this same type of information for Hg, HCl, and HF 
CEMS, with the addition of a few codes for the new parameters.
    The second type of data collected through ECMPS is certification 
and QA test data. These data include data from linearity checks, RATAs, 
cycle time tests, 7-day calibration error tests, and a number of other 
QA tests that are required to validate the emissions data. You may 
submit the results of these tests to the EPA as soon as you obtain the 
results, with one notable exception. Daily calibration error tests are 
not treated as individual QA tests, due to the large number of records 
generated each quarter. Rather, these tests must be included in the 
quarterly electronic reports, along with the hourly emissions data. The 
ECMPS system is set up to receive and process certification and QA data 
from SO2, CO2, O2, flow rate, and 
moisture monitoring systems that are installed, certified, maintained, 
operated, and quality-assured according to 40 CFR part 75. EGUs 
routinely submit these data to the EPA under the ARP and other 
emissions trading programs.
    To accommodate the certification and QA tests for Hg CEMS, other 
CEMS, and sorbent trap monitoring systems, the structure and 
functionality of ECMPS needs relatively few changes, because most of 
the tests are the same as those required for other gas monitors. For 
reporting Hg, HCl, SO2, and HF CEMS data under this rule, we 
are disabling ECMPS' 40 CFR part 75 bias test (which is required for 
certain types of monitors under the EPA's SO2 and 
NOX emissions trading programs). The bias adjustment of the 
data from these monitors is unnecessary for compliance with the rule.
    The third type of data collected through ECMPS is the hourly 
emissions data, which, as previously noted, is reported on a quarterly 
schedule. You must submit reports within 30 days after the end of each 
calendar quarter. The emissions data format requires hourly reporting 
of all measured and calculated emissions values, in a standardized 
electronic format. You must report direct measurements made with CEMS, 
such as gas concentrations, in a Monitor Hourly Value (MHV) record. A 
typical MHV record for gas concentration includes data fields for:
    (1) The parameter monitored (e.g., SO2);
    (2) The unadjusted and bias-adjusted hourly concentration values 
(note that if bias adjustment is not required, only the unadjusted 
hourly value is reported);
    (3) The source of the data, i.e., a code indicating either that 
each reported hourly concentration is a quality assured value from a 
primary or backup monitor, or that quality-assured data were not 
obtained for the hour; and
    (4) The percent monitor availability (PMA), which is updated hour-
by-hour. This generic record structure could easily accommodate hourly 
average measurements from CEMS used under this rule.
    The ECMPS reporting structure is quite flexible, which makes it 
useful for assessing compliance with various emission limits. The 
Derived Hourly Value (DHV) record allows calculations of a wide variety 
of quantities from the reported hourly emissions data. For instance, if 
an emission limit is expressed in units of lb/MMBtu, the DHV record can 
be used to report hourly pollutant concentration values in these units 
of measure, since the lb/MMBtu values can be derived from the hourly 
pollutant and diluent gas (CO2 or O2) 
concentrations reported in the MHV records. The ECMPS can also 
accommodate multiple DHV records for a given hour in which more than 
one derived value is required to be reported. The system will support 
reporting hourly data in the units of the emission standards (e.g., lb/
MMBtu, lb/TBtu, lb/GWh, etc.) when hourly Hg concentration data are 
reported through ECMPS using the DHV record, in conjunction with the 
appropriate equations and auxiliary information such as heat input and 
electrical load (all of which are reported hourly in the emissions 
reports).
    One change in this rule from standard 40 CFR part 75 emissions data 
reporting is elimination of the requirement to provide substitute data 
calculations within ECMPS. The ARP and other emissions trading programs 
that report emissions data to the EPA using 40 CFR part 75 require 
provision of a complete data record. Emissions data are required to be 
reported for every unit operating hour. When CEMS are out of service, 
substitute data must be reported to fill in the gaps. However, for the 
purposes of compliance with a NESHAP, reporting substitute data during 
monitor outages is not necessary, as quantification of total mass 
emissions is not the focus of the rule. Hours when a monitoring system 
is out of service would be counted as hours of monitor down-time and 
may be a deviation from the monitoring requirements of this rule unless 
the rule provides an exception, as it does for routine quality control 
and maintenance activities.
    In contrast to the CEMS-related data that would be submitted 
through ECMPS, you must submit reports of performance tests and PM CPMS 
data to EPA's WebFIRE database by using CEDRI that is accessed through 
EPA's

[[Page 9376]]

CDX (www.epa.gov/cdx). You must submit performance test data in the 
file format generated through use of EPA's ERT (see http://www.epa.gov/ttn/chief/ert/index.html) within 60 days of performance test 
completion. Electronic data submittal requirements are described in 
section V.H. of this preamble.
    Other notifications and reports not currently accepted by the 
electronic reporting system will be submitted in hardcopy form at this 
time.

VI. Summary of Significant Changes Since Proposal

    The previous section described the requirements that EPA is 
finalizing in this rule. This section will discuss in greater detail 
the key changes EPA is making from the proposed. These changes result 
from EPA's review of the additional data and information provided to us 
and our consideration of the many substantive and thoughtful comments 
submitted on the proposal. While our approach and methodology to 
establishing the standards remain the same, the changes make the final 
rule more flexible and cost-effective, reduce reliability concerns and 
improve clarity, while fully preserving, or improving, the public 
health and environmental protection required by the CAA.

A. Applicability

    Since proposal, the EPA has made certain changes to the 
applicability provisions of the final rule to provide clarity. These 
changes do not change the universe of sources subject to the rule.
    The EPA is revising a number of the proposed definitions and adding 
a definition for ``natural gas-fired electric utility steam generating 
unit'' in the final rule to provide clarity to the regulated community 
concerning the standards applicable to coal- and oil-fired EGUs.
    In the proposed rule, the EPA defined ``[e]lectric utility steam 
generating unit'' consistent with the CAA section 112(a)(8) definition:

    A fossil fuel-fired combustion unit of more than 25 megawatts 
electric (MWe) that serves a generator that produces electricity for 
sale. A fossil fuel-fired unit that cogenerates steam and 
electricity and supplies more than one-third of its potential 
electric output capacity and more than 25 MWe output to any utility 
power distribution system for sale is considered an electric utility 
steam generating unit.

40 CFR 63.10042.

    We also indicated how we would determine whether units were coal-
fired or oil-fired fired EGUs: ``If an EGU burns coal (either as a 
primary fuel or as a supplementary fuel), or any combination of coal 
with another fuel (except solid waste as noted below), the unit is 
considered to be coal fired under this proposed rule. If a unit is not 
a coal-fired unit and burns only oil, or oil in combination with 
another fuel other than coal (except as noted below), the unit is 
considered to be oil fired under this proposed rule.'' 76 FR 25020.
    We proposed a definition for the term ``fossil fuel-fired'' because 
that term was not defined in the statute and we wanted to clarify the 
level of fossil fuel combustion necessary to satisfy the CAA section 
112(a)(8) definition of EGU. The definition focused on coal and oil 
combustion because the EPA was only regulating coal- and oil-fired EGUs 
in this final rule. The proposed definition contained two primary 
elements: (1) the unit must be capable of combusting sufficient amounts 
of coal or oil to generate the equivalent of 25 megawatts electrical 
output; and (2) the unit must have fired coal or oil for more than 10.0 
percent of the average annual heat input during the previous 3 calendar 
years or for more than 15.0 percent of the annual heat input during any 
one of those calendar years. 76 FR 25025. We further stated that for a 
unit to be ``capable of combusting'' coal or oil the unit must have a 
permit that authorized the combustion of coal or oil and also have the 
appropriate fuel handling facilities on-site. Id.
    As explained in the proposed rule, natural gas-fired EGUs were not 
included in the December 2000 listing so such units that otherwise met 
the CAA section 112(a)(8) definition of EGU because of natural gas 
combustion are not subject to the final rule. In the proposed rule, we 
stated that an EGU that ``combusts natural gas exclusively or natural 
gas in combination with another fuel where the natural gas constitutes 
90 percent or more of the average annual heat input during the previous 
3 calendar years or 85.0 percent or more of the annual heat input 
during any one of those calendar years'' was not subject to the rule. 
Id. The references to 90 percent natural gas combustion over 3 years 
and 85 percent natural gas combustion in any one year were included to 
align with the definitions of ``fossil fuel-fired'' so that it would be 
clear that units combusting primarily natural gas would not be 
considered coal-fired, oil-fired, or IGCC EGUs if they burned 10 
percent or less of coal, oil, or synthetic gas derived from coal or 
solid oil over 3 years or 15 percent or less of such fuels in any one 
year. We did not intend to suggest that to be considered a fossil fuel-
fired EGU a natural gas-fired unit that is not a coal-fired or oil-
fired EGU would have to combust natural gas that exceeded the 10 
percent/15 percent thresholds set forth in the proposed rule. In fact, 
in 40 CFR 63.9983 of the proposed rule, we stated that ``[a]ny EGU that 
is not a coal- or oil-fired EGU and combusts natural gas more than 10.0 
percent of the average annual heat input during the previous 3 calendar 
years or for more than 15.0 percent of the annual heat input during any 
one of those calendar years'' is not subject to this subpart.
    We further explained that the percentages included in the 
definition of ``fossil fuel-fired'' would prevent units that primarily 
combusted fuels other than fossil fuels from being subjected to the 
final rule:

    Units that do not meet the definition of fossil-fuel fired 
would, in most cases, be considered IB units subject to one of the 
Boiler NESHAP. Thus, for example, a biomass-fired EGU, regardless of 
size, that utilizes fossil fuels for startup and flame stabilization 
purposes only (i.e., less than or equal to 250 MMBtu/hr and used 
less than 10.0 percent of the average annual heat input during the 
previous 3 calendar years or less than 15.0 percent of the annual 
heat input during any one of those calendar years) is not considered 
to be a fossil fuel-fired EGU under this proposed rule. The EPA has 
based its threshold value on the definition of ``oil-fired'' in the 
ARP found at 40 CFR 72.2. As EPA has no data on such use for (e.g.) 
biomass co-fired EGUs because their use has not yet become 
commonplace, we believe this definition also accounts for the use of 
fossil fuels for flame stabilization use without inappropriately 
subjecting such units to this proposed rule. Id.

    Thus, in the proposed rule, we intended to create thresholds to 
determine when a unit is fossil fuel-fired and for which fossil fuel 
the unit is fossil fuel-fired. We intended to include a unit combusting 
more than the defined amount of coal in one of the coal-fired EGU 
subcategories. If a unit is not coal-fired and it is combusting more 
than the defined amount of oil, we intended to include the unit in one 
of the oil-fired EGU subcategories. We also intended to make clear that 
EGUs that are neither coal-fired nor oil-fired but combust more than 
the defined amount of natural gas are natural gas-fired EGUs not 
subject to the final standards. However, the definitions, as proposed, 
were not sufficiently descriptive.
    For example, we included a definition for ``coal-fired electric 
utility steam generating unit'' that did not include the requirement 
that the unit must combust coal for at least 10 percent of the heat 
input over 3 years or 15 percent of the heat input in any one year. 
Instead, in the proposed rule we indicated that a unit was coal-fired 
if it burned coal in any amount. We did not intend to

[[Page 9377]]

define a unit as coal-fired if it burned coal that accounted for 10 
percent or less over 3 years or 15 percent of less in any one year, as 
that would be inconsistent with the definition of fossil fuel-fired and 
the definitions for the oil-fired EGU subcategories. Under the proposed 
rule construct, a unit that combusts mostly biomass and less than 10 
percent coal over 3 years would not be a coal-fired EGU because it 
would not meet the ``fossil fuel-fired'' definition. But a unit burning 
mostly petroleum coke and less than 10 percent coal over 3 years might 
be considered a coal-fired EGU because it would meet the definition of 
``fossil fuel-fired'' and be burning some coal, even though that level 
of coal combustion alone would not be sufficient to make the unit 
``fossil fuel-fired'' for coal. That result is at odds with our intent. 
The same would hold true for an EGU that combusts mostly natural gas 
and less than 10 percent synthetic gas derived from coal over a 3-year 
period. Our proposal preamble makes clear that we did not intend this 
result because we specifically stated that units burning 90 percent or 
more natural gas over a 3-year period would be considered natural-gas 
fired EGUs. 76 FR 25025.
    In addition, we proposed to define ``[u]nit designed to burn solid 
oil fuel subcategory'' to include any EGU that burned a solid fuel 
derived from oil for more than 10.0 percent of the average annual heat 
input during the previous 3 calendar years or for more than 15.0 
percent of the annual heat input during any one of those calendar 
years, either alone or in combination with other fuels. We also 
included the 10 percent/15 percent thresholds in the definition for the 
liquid oil subcategory, but, as stated above, we did not include the 
thresholds in the definition of ``coal-fired'' EGU. Therefore, there 
would be some confusion for a source that blended coal with solid oil 
derived fuel (e.g., petroleum coke). For example, the owner or operator 
of an EGU that burned sufficient solid oil-derived fuel that accounted 
for 80 percent of the heat input in a given year and the remainder of 
the fuel was coal would not be sure which standard applied because the 
definitions in the proposed rule were internally inconsistent.
    For these reasons, we are revising the definitions for ``coal-fired 
electric utility steam generating unit,'' ``integrated gasification 
combined cycle electric utility steam generating unit,'' and ``oil-
fired electric utility steam generating unit,'' and we are adding a 
definition of ``natural-gas fired electric utility steam generating 
unit'' as set out in 40 CFR 63.10042.
    In addition to these changes, we are revising the definition of 
``fossil fuel-fired'' based on comments. We are revising the definition 
to remove the heat input equivalent of 25 MW because commenters noted 
that the equivalency used (taken from 40 CFR part 60, subpart Da) could 
not be applied consistently because of differing boiler efficiencies. 
Commenters noted that owners/operators were familiar with the use of 
the ``MW'' term for the boilers and boilers include nameplate 
capacities that are readily identifiable.
    We are also including a revision to the definition so that the 
fossil fuel combustion thresholds of 10 percent over 3 consecutive 
years and 15 percent in one year are evaluated after the applicable 
compliance date of the final rule on a rolling basis. Commenters 
correctly noted that some existing coal- and oil-fired EGUs will 
convert their units to alternative fuels (e.g., natural gas or biomass) 
and if the definition were finalized as proposed such units could be 
improperly subjected to the final standards.
    The new definition is set out in 40 CFR 63.10042.
    For clarity, we are also removing the definition of ``[u]nit 
designed to burn liquid oil fuel subcategory,'' revising the definition 
of ``[u]nit designed to burn solid oil fuel subcategory,'' adding 
definitions for the continental and non-continental liquid oil-fired 
EGU subcategories, and adding a definition of a limited-use liquid oil-
fired EGU as set out in 40 CFR 63.10042.
    In the proposed rule, we stated that we believed EGUs may at times 
not meet the definition of an EGU subject to this subpart. For example, 
we explained that there may be some cogeneration units that are 
determined to be covered under the Boiler NESHAP. Such unit(s) may make 
a decision to increase the proportion of production output being 
supplied to the electric utility grid, thus causing the unit(s) to meet 
the EGU cogeneration criteria (i.e., greater than one-third of its 
potential output capacity and greater than 25 MW). In the preamble to 
the proposed rule, we indicated that a unit subject to one of the 
Boiler NESHAP that increases its electricity output and meets the 
definition of an EGU would be subject to the EGU NESHAP for the 6-month 
period after the unit meets the EGU definition.\310\ 76 FR 25026. 
Assuming the EGU did not meet the definition of an EGU following that 
initial occurrence, at the end of the 6-month period it would revert 
back to being subject to the Boiler NESHAP, or other applicable 
standard. We solicited comment on the extent to which situations like 
this might occur, how the EPA should address situations where units 
change applicability, and whether we should include provisions similar 
to those included in the final CISWI (40 CFR 60.2145) to address such 
situations. Id.
---------------------------------------------------------------------------

    \310\ Although we clearly stated the intent to require sources 
to comply for 6 months after meeting the definition of an EGU, we 
inadvertently failed to include the provision in the proposed rule.
---------------------------------------------------------------------------

    Several commenters asked the Agency to include provisions in the 
final rule that would address situations like the ones described in the 
preamble to the proposed rule. Because applicability to the final rule 
is based in part on the statutory definition of an EGU is CAA section 
112(a)(8), similar to the situation with units combusting solid waste 
under CAA section 129(g)(1) (e.g., CISWI Rule), we are adopting 
provisions in the final rule that are based on the fuel switching 
provisions of the final CISWI Rule (See Final CISWI Rule, 40 CFR 
60.2145). For example, a cogeneration unit that did not historically 
provide more than one third of its potential electrical output capacity 
to a power distribution system could change its output and provide more 
than 25 megawatts electrical output to any power distribution system 
for sale. Such units would be subject to MATS. If the cogeneration unit 
later reduced its output such that it no longer met the definition of 
an EGU, that source would nevertheless remain subject to MATS for at 
least 6 months from the date that the unit first qualified as an EGU.
    In addition, we are finalizing a provision whereby you may opt to 
remain subject to the provisions of this final rule, unless you combust 
solid waste, in which case you are a solid waste incineration unit 
subject to standards under CAA section 129 (e.g., 40 CFR part 60, 
subpart CCCC (New Source Performance Standards (NSPS) for Commercial 
and Industrial Solid Waste Incineration Units), or subpart DDDD 
(Emissions Guidelines (EG) for Existing Commercial and Industrial Solid 
Waste Incineration Units)). We believe the provision to opt to remain 
subject to this final rule will ameliorate conditions where EGUs may 
potentially move between NESHAP on a relatively frequent basis. 
Notwithstanding the provisions of this final rule, an EGU that starts 
combusting solid waste is subject to standards under CAA section 129, 
and the unit remains subject to those standards until the unit no 
longer meets the definition of a solid waste incineration unit 
consistent with the provisions of the applicable CAA section 129 
standards.

[[Page 9378]]

    The changes to the definitions described above provide clarity to 
sources, permitting agencies, and the public about the applicability of 
the rule and help ensure that sources are appropriately covered by the 
regulation.

B. Subcategories

    In this final rule, the EPA is adding subcategories for limited-use 
oil-fired units and non-continental oil-fired units and revising the 
definitions for the coal-fired EGU subcategories.
    The proposed rule subcategorized EGUs burning coal into two 
subcategories: EGUs designed for coal >=8,300 Btu/lb and EGUs designed 
for virgin coal <8,300 Btu/lb (low rank virgin coal). We received a 
number of comments indicating that the definition of the low rank 
virgin coal subcategory was technically deficient.
    Under CAA section 112(d)(1), the Administrator has the discretion 
to ``* * * distinguish among classes, types, and sizes of sources 
within a category or subcategory in establishing * * *'' standards. The 
EPA maintains that, normally, any basis for subcategorization (i.e., 
class, type, or size) must be related to an effect on HAP emissions 
that is due to the difference in class, type, or size of the units. See 
76 FR 25036-25037. The EPA believes it is not reasonable to exercise 
our discretion without such a difference because if sources can achieve 
the same level of emissions reductions notwithstanding a difference in 
class, type, or size, the purposes of CAA section 112 are better served 
by requiring a similar level of control for all such units in the 
category or subcategory. See Lignite Energy Council v. EPA, 198 F. 3d 
930, 933 (D.C. Cir. 1999) (``EPA is not required by law to 
subcategorize--section 111[b][2] merely states that `the Administrator 
may distinguish among classes, types, and sizes within categories of 
new sources''' (emphasis original)); see also CAA section 112(d)(1) 
(containing almost identical language to CAA section 111, CAA section 
112(d)(1) provides that ``the Administrator may distinguish among 
classes, types, and sizes of sources within a category or subcategory 
in establishing [ ] standards * * *''). Even if we determine that 
emissions characteristics are different for units that differ in class, 
type, or size, the Agency may still decline to subcategorize if there 
are compelling policy justifications that suggest subcategorization is 
not appropriate. Id.
    When developing the proposed rule, we examined the EGUs in the top 
performing 12 percent of sources for Hg emissions. We determined that:

    There were no EGUs designed to burn a nonagglomerating virgin 
coal having a calorific value (moist, mineral matter-free basis) of 
19,305 kJ/kg (8,300 Btu/lb) or less in an EGU with a height-to-depth 
ratio of 3.82 or greater among the top performing 12 percent of 
sources for Hg emissions, indicating a difference in the emissions 
for this HAP from these types of units. The boiler of a coal-fired 
EGU designed to burn coal with that heat value is bigger than a 
boiler designed to burn coals with higher heat values to account for 
the larger volume of coal that must be combusted to generate the 
desired level of electricity. Because the emissions of Hg are 
different between these two subcategories, we are proposing to 
establish different Hg emission limits for the two coal-fired 
subcategories. For all other HAP from these two subcategories of 
coal-fired units, the data did not show any difference in the level 
of the HAP emissions and, therefore, we have determined that it is 
not reasonable to establish separate emissions limits for the other 
HAP. 76 FR 25036-67.

    Based on this determination, we proposed to establish two 
subcategories with separate Hg limits. Comments on the proposed rule 
indicate that we correctly identified the EGUs that should be included 
in each subcategory, but the comments also demonstrated that we made 
certain incorrect conclusions that require us to revise the definitions 
of our coal-fired EGU subcategories. The revised definitions ensure 
that the EGUs we identified at proposal as having different Hg 
emissions remain in one subcategory.
    As stated above, we believed at proposal that the boiler size was 
the cause of the different Hg emissions characteristics that led us to 
propose subcategorization, but many commenters indicated that it was 
not the boiler size but the fact that the EGUs burned a 
nonagglomerating virgin coal having a calorific value (moist, mineral 
matter-free basis) of less than 19,305 kJ/kg (8,300 Btu/lb) (low rank 
virgin coal) that causes the disparity in Hg emissions. Several 
commenters indicated that their EGUs were designed to burn and burned 
low rank virgin coal but the units did not meet the height-to-depth 
ratio that EPA proposed. For example, the height-to-depth ratio of 
certain EGUs in this subcategory is in fact 3.5, not 3.82. Further, 
there are other EGUs in this subcategory that are circulating fluidized 
bed (CFB) combustion units which do not meet the height-to-depth ratio 
parameters in the proposed rule, nor are they anything like the 
pulverized coal (PC) EGUs we initially identified as having the 3.82 
height-to-depth ratio.
    In addition to the comments concerning EGUs firing this coal, we 
received comments from at least two commenters indicating that the EPA 
should clarify in which subcategory a unit belongs when it does not 
burn low rank virgin coal but is designed to combust low rank virgin 
coal and has a height-to-depth ratio of greater than 3.82. Commenters 
also indicated that CFB units that are burning coal-refuse \311\ or 
other nonagglomerating virgin coal having a calorific value (moist, 
mineral matter-free basis) of 19,305 kJ/kg (8,300 Btu/lb) or greater 
are ``designed to burn'' any type of coal. Owners of CFB units that are 
not firing low rank virgin coal asked which subcategory they belong to 
based on their ability to burn any type of coal (including low rank 
virgin coal) without modification. These commenters also indicated that 
some coal refuse that is combusted has a heating value less than 8,300 
Btu/lb but is not ``virgin coal.'' It was unclear to which subcategory 
they belonged since the proposed rule did not in fact require the unit 
to burn any specific coal, instead only requiring the unit be 
``designed'' to burn lower Btu coal.
---------------------------------------------------------------------------

    \311\ It is our understanding that no unit combusts coal-refuse 
from nonagglomerating virgin coal having a calorific value (moist, 
mineral matter-free basis) of less than 19,305 kJ/kg (8,300 Btu/lb).
---------------------------------------------------------------------------

    Based on the comments received, we reevaluated the subcategory 
definitions because we were concerned that the definitions we proposed 
would improperly categorize a number of the EGUs in both subcategories. 
We concluded that we should not maintain the proposed definition for 
``[u]nits designed for coal <8,300 Btu/lb'' and exclude the CFB units 
and PC EGUs with a height-to-depth ratio less than 3.82 that combusted 
low rank virgin coal.
    We were equally concerned that the subcategory definitions not be 
revised in a manner that would move EGUs that we believed the data show 
could comply with a more stringent standard into a subcategory with a 
less stringent standard because, aside from the type of EGUs we 
identified, all other classes, types, and sizes of EGUs were 
represented among the top performing 12 percent for Hg in the >=8,300 
Btu/lb subcategory. We were particularly concerned about the CFB units 
because other CFB units are well represented among the best performing 
EGUs for Hg in the >=8,300 Btu/lb subcategory, but the CFB units 
burning low rank virgin coal are not achieving the same levels of Hg 
emissions control. Including the best performing CFB units from the 
other subcategory in the low rank virgin coal subcategory would likely 
lead to a Hg standard as stringent as the standard for

[[Page 9379]]

EGUs in the >=8,300 Btu/lb subcategory because the CFB units from the 
other subcategory would be used to establish the floor. We believe that 
result would be inconsistent with the intent of the proposed rule. We 
were also concerned about the information that some EGUs that fired low 
rank virgin coal had a height-to-depth ratio of 3.5, not 3.82, and that 
some EGUs that fired other ranks of coal had a height-to-depth ratio 
greater than 3.82. For these reasons, we did not revise the definition 
to include CFB units and PC EGUs with a height-to-depth ratio greater 
than 3.5.
    After fully considering the available information, including the 
comments received, we have concluded that it is appropriate to continue 
to base the subcategory definitions, at least in part, on whether the 
EGUs were designed to burn and, in fact, did burn low rank-virgin coal, 
but that it is not appropriate to continue to use the height-to-depth 
ratio criteria because that approach would potentially exclude EGUs we 
identified as having different Hg emission characteristics and include 
EGUs that did not have different emissions characteristics. We 
recognize that some commenters have taken the position that it is 
unlawful to subcategorize based on factors such as fuel type but 
nothing in the statute prohibits such an approach and the case law 
supports this approach to the extent courts have considered 
subcategorization based on such factors. See Sierra Club v. Costle, 657 
F. 2d 298, 318-19 (D.C. Cir. 1981) (differing pollutant content of 
input material can justify a different standard based on 
subcategorization authority to ``distinguish among classes, types and 
sizes within categories of new sources''). Furthermore, we believe had 
Congress intended to prohibit the EPA from subcategorizing based on an 
EGU being designed to use and using a certain material input (e.g., 
fuel) it would have clearly stated such intent in the CAA. However, we 
believe the Agency could decline to exercise its discretion to 
subcategorize even if the potential result would be the prohibition of 
the use of some materials if the circumstances warranted. We note that 
even if we did not subcategorize on the final basis selected, the Hg 
emissions standard of 1.2E0 lb/Tbtu for the ``unit designed for coal 
>=8,300 Btu/lb'' would remain the same.
    We considered basing the subcategory solely on an EGU being 
designed to burn and burning low rank virgin coal. We decided not to do 
so because we were concerned that such a definition would allow sources 
to potentially meet the definition by combusting very small amounts of 
low rank virgin coal. For example, an EGU on the east coast (or any 
other region) that was not designed to burn and did not routinely burn 
low rank virgin coal could import one truck full of low rank virgin 
coal and burn a very small quantity of it periodically to meet the 
subcategory definition. To avoid creating this potential loophole, we 
considered other characteristics that would distinguish EGUs combusting 
low rank virgin coal.
    We determined that these EGUs are universally constructed ``at or 
near'' a mine containing low rank virgin coal because it is not cost-
effective to transport large quantities of such fuel long distances. 
Furthermore, we believe that this subcategory of EGUs are almost always 
built at a mine and limited transportation of the coal is only required 
as the mine face moves over the course of time. Many such EGUs 
construct dedicated rail lines, private roads, or conveyor systems to 
transport the coal to the EGU as the mine face moves. We obtained 
information from data acquired to develop the CSAPR indicating that the 
longest distance any EGU firing low rank virgin coal transports that 
coal is 40 miles. We believe that this distance is near the outer 
limits for the transport of such coal, but, even for those EGUs, the 
EGUs were constructed closer to a now idle mine or closer to the 
working face of a mine that has now expanded away from the EGU site. 
For these reasons, we are including a requirement that the unit be 
constructed and operated at or near a mine containing the low rank 
virgin coal it burns.
    We are revising the coal-fired EGU subcategory definitions as set 
out in 40 CFR 63.10042.
    We believe the revised subcategory definitions are reasonable for 
all the reasons set forth above. The revised definitions maintain the 
EGUs we identified as having different Hg emissions characteristics in 
one subcategory and the definitions prevent other EGUs that are not 
firing low rank virgin coal from being required to comply only with the 
less stringent Hg emission standard.
    As discussed in response to comments, we do not believe that 
additional subcategorization of other coal-fired EGUs is reasonable or 
appropriate. All other coal-fired EGUs that are not designed to burn 
and are burning low rank virgin coal are represented among the best 
performing sources for Hg, such that no argument exists to support that 
the Hg emissions from those EGUs are different. In any case, even if 
emissions are somewhat different as some commenters suggest, we would 
decline to exercise our discretion because the data demonstrate that 
the best performing EGUs designed to burn and burning all other ranks 
of coal are able to achieve the MACT level of control using currently 
available controls and other HAP emission reduction mechanisms (e.g., 
coal washing) for the >=8,300 Btu/lb subcategory.
    A second issue related to subcategorization concerns non-
continental liquid oil-fired EGUs. At proposal, the EPA did not have 
sufficient emissions data from non-continental liquid oil-fired EGUs 
upon which to base a subcategory and took comment on the issue. The 
data have since been provided in response to the ICR and we received 
comments suggesting that a non-continental subcategory is appropriate 
based on the location of such units, the limited availability of 
alternative fuel sources, and the fact that the emissions 
characteristics of such units are distinct from continental liquid oil-
fired EGUs. The EPA has evaluated the data and comments and we agree 
that a subcategory is warranted based for the reasons suggested by the 
commenters. Therefore, the Agency is finalizing the liquid oil-fired 
EGU subcategories of ``continental'' and ``non-continental.''
    Lastly, the EPA did not have sufficient information on limited-use 
liquid oil-fired EGUs upon which to base a subcategory at proposal 
because some sources required to test under the ICR did not submit the 
data until after proposal. We took comment on whether a limited-use 
subcategory was warranted. Commenters indicated that their units were a 
different class and type of units because many of them were only called 
to service to address reliability issues associated with, for example, 
natural gas curtailments. The commenters further indicated that their 
units are different because of the generally infrequent use and the 
sporadic, and at times frequent, start-up and shutdown periods (e.g., 
they are often only required to run for a couple of hours). These 
factors would lead to differences in the emissions characteristics for 
these units such that a numeric standard based on base load units would 
not likely be achievable during the very limited times that these 
limited use oil-fired units operate. Based on comments received and our 
own analysis, we are finalizing a subcategory for limited-use liquid 
oil-fired EGUs as discussed further elsewhere in this preamble.

[[Page 9380]]

C. Emission Limits

    The proposed rule included numerical emission limits for PM, Hg, 
HCl, HF, SO2, total HAP metals, and individual HAP metals, 
depending on the subcategory and specific situation. These proposed 
limits resulted from calculations of MACT floors using information and 
data available to the Agency prior to proposal, as required by CAA 
section 112. Based on information and data received during the comment 
period, we have made data and calculation corrections where necessary 
and then re-ranked the best performing units in the MACT floor pools. 
Based on the new ranking, a limited number of the emission limits in 
the final rule have changed from those proposed.
    In addition to adjustments to the emission limits themselves, we 
are finalizing several other changes to the emission standards that 
will simplify and improve compliance for sources without compromising 
the toxics reductions achieved. One key change, as discussed elsewhere 
in this notice, is that we have changed the surrogate for non-mercury 
metallic HAP from total particulate matter (PM) to filterable PM for 
coal-fired and solid oil-derived EGUs. This change is based on 
information provided in comments and our own conclusion that 
measurement of filterable PM provided assurance of equivalent HAP 
emissions control. Most of the non-mercury metal HAP, for which PM is a 
surrogate, are filterable PM and the one that is not (Se) is well 
controlled by the limit on acid gases. Using filterable PM as the 
surrogate will allow us to use continuous PM monitoring systems, which 
measure filterable (but not total) PM, thereby providing a more 
continuous measure of compliance.
    For liquid oil-fired EGUs, based on comments received and 
corrections made to the data submitted, we have added a filterable PM 
limit in the final rule as an alternative equivalent standard for the 
total metal-HAP limit in the proposed rule. In addition, as discussed 
elsewhere in this notice, we have added measurement of the moisture 
content of the oil (with a 1 percent limit) as an alternate compliance 
assurance measure for liquid oil-fired EGUs for determining compliance 
with the HCl and HF limits. Direct measurement of HCl and HF remains a 
compliance demonstration method in the final rule. Finally, as 
discussed in section VI.D of this notice, the final work practice 
standard consisting of burner tune-ups, much like those required for 
organic HAP control, for those limited-use liquid oil-fired EGUs whose 
annual capacity factor is less than 8 percent.

D. Work Practice Standards for Organic HAP Emissions

    As noted earlier in section V.D., the final rule includes a work 
practice standard for organic HAP, including dioxins and furans, 
applicable to all EGUs. As noted in section V.D. above, the majority of 
emissions of these pollutants are below the detection levels of EPA 
test methods and, therefore, are impractical to measure. The work 
practice standard, described below, is a practical approach to ensuring 
that equipment is maintained and run so as to minimize emissions of 
dioxins and furans, and we expect it to be more effective than 
establishing a numeric standard that cannot reliably be measured or 
monitored. The work practice also applies to the limited-use liquid 
oil-fired subcategory included in the final rule.
    The work practice involves maintaining and inspecting the burners 
and associated combustion controls (as applicable), tuning the specific 
burner type to optimize combustion, obtaining and recording CO and 
NOX values before and after the burner adjustments, keeping 
records of activity and measurements, and submitting a report for each 
tune-up conducted. In Table 3 of the final regulation, we have 
clarified that this refers to performance tune-ups, not tests, and have 
addressed the frequency requirement as discussed in response to 
comments about the appropriateness of the 18-month frequency. The 
provisions of 40 CFR 63.10006(h)(i) refer to 40 CFR 63.10021(e) for the 
specific steps required to be part of the periodic tune-up. We have 
also adjusted the language in the final rule to recognize the value of 
automated boiler optimization tools such as neural network systems.
    Under the final rule, the tune-up must be conducted at each planned 
major outage and in no event less frequently than every 36 calendar 
months, with an exception that if the unit employs a neural-network 
system for combustion optimization during hours of normal unit 
operation, the required frequency is a minimum of once every 4 years 
(48 calendar months). Initial compliance with the work practice 
standard of maintaining burners must occur within 180 days of the 
compliance date of the rule. The initial compliance demonstration for 
the work practice standard of conducting a tune-up may occur prior to 
the compliance date of the rule, but must occur no later than 42 months 
(36 months plus 180 days) from the compliance date of the rule or, in 
the case of units employing neural network combustion controls, 54 
months (48 months plus 180 days). If the tune-up occurs prior to the 
compliance date of the rule, you must maintain adequate records to show 
that the tune-up met the requirements of this standard.
    We have made a number of specific changes to address what to do for 
repairs that may require longer term corrective actions, additional 
methods for evaluating combustion effectiveness, and clarification on 
procedures for recording CO and NOX information. There were 
specific comments that opposed the reference to manufacturer 
specifications, if available. We retained this language in the final 
rule, but note that these specifications apply only to the extent 
applicable. Specifically, if manufacturer specifications only address 
equipment or conditions that are no longer present given current boiler 
operations, then those specifications are not applicable and other 
combustion engineering best practice procedures for that burner type 
would apply. We have also clarified that portable emission monitoring 
equipment may be used to collect the required emissions optimization 
data regarding pre- and post-tune-up CO and NOX emission 
levels.

E. Requirements During Startup, Shutdown, and Malfunction

    We proposed numerical emission standards that would apply at all 
times, including during periods of startup, shutdown, and malfunction. 
Although at proposal we stated that we were not setting a different 
standard for startup and shutdown, we did propose different standards 
for startup and shutdown by our inclusion of the default values 
described below, which applied only during startup and shutdown. 
Specifically, we stated:

    To appropriately determine emissions during startup and shutdown 
and account for those emissions in assessing compliance with the 
proposed emission standards, we propose use of a default diluent 
value of 10.0 percent O2 or the corresponding fuel 
specific CO2 concentration for calculating emissions in 
units of lb/MMBtu or lb/TBtu during startup or shutdown periods. For 
calculating emissions in units of lb/MWh or lb/GWh, we propose 
source owners use an electrical production rate of 5 percent of 
rated capacity during periods of startup or shutdown. We recognize 
that there are other approaches for determining emissions during 
periods of startup and shutdown, and we request comment on those 
approaches. We further solicit comment on the proposed approach 
described above and whether the values we are proposing are 
appropriate.


[[Page 9381]]


    We proposed application of the respective emission limits during 
periods of startup and shutdown and use of default values to calculate 
the emission limits. The standards that apply at all times other than 
startup and shutdown are production-based limits, which is why we 
proposed the default values. The default values were meant to account 
for the fact that during startup and shutdown events, production (in 
this case the generation of electricity) is by definition nonexistent. 
Thus, in effect, we proposed a separate standard to apply during 
startup and shutdown.
    We received a variety of comments on the proposed standards that 
would apply during startup and shutdown. Many commenters pointed to the 
lack of data in the record concerning emissions that occur during 
periods of startup and shutdown. They further asserted that emissions 
during these periods can be highly variable in light of the sequence of 
events that occurs during the startup and shutdown of an EGU. Although 
a number of commenters supported the use of the diluent factor 
approach, including the default 5 percent of rated capacity, during 
startup/shutdown periods, other commenters questioned the feasibility 
of collecting additional data during such periods and had concerns 
regarding the reliability of measurements obtained from EGUs during 
such periods.
    In response to the Agency's ICR to the utility industry, seven 
owners or operators indicated that they provided startup and shutdown 
data for their EGUs. These data were submitted in response to the 
requirement in the ICR to provide all available data from the 5 years 
prior to the date the ICR was issued. Of these data, there were almost 
no HAP data for startup and shutdown periods and almost all of the data 
failed to meet our data quality requirements.\312\ Thus, we do not have 
sufficient data on emissions that occur during startup and shutdown on 
which to set emission standards. We are therefore establishing work 
practice standards rather than numeric emissions standards for periods 
of startup and shutdown in the final rule. Before we describe those 
work practices, we first address what constitutes startup and shutdown.
---------------------------------------------------------------------------

    \312\ In response to the ICR, we also received SO2 
CEMS data and the Agency had additional SO2 CEMS data 
available through the CAMD ARP database. We are not able to identify 
specific periods of start-up and shutdown in either the ICR CEMS 
data or the CAMD ARP data, and the ICR respondents do not indicate 
that the ICR data includes periods of startup and shutdown. We set 
the emission limits for SO2 and HCl using the data 
provided to the EPA from the 2010 ICR, not the CAMD data, since 
those data were taken concurrently under the same specified 
operating conditions using the same fuel. We used the SO2 
CEMS data that was submitted in response to the ICR by converting it 
to single point data to correlate to the data from units that did 
not provide CEMS data from the relevant testing period. The 
emissions limits for the NESHAP incorporated variability by applying 
the 99 percent UPL to the average emissions developed from the stack 
test data and SO2 CEMS data that was converted to stack 
test data. Thus, we did not have data on which to establish an 
SO2 standard during periods of startup and shutdown and 
the numeric standards do not apply to those periods in the final 
rule. In contrast, the NSPS for SO2 is applicable during 
periods of startup and shutdown since the long term CAMD ARP CEMS 
data were used to determine the average performance of the best 
demonstrated technology. Those long term data were assumed to 
incorporate process variability including that associated with fuel 
and process/operational changes and periods of startup and shutdown.
---------------------------------------------------------------------------

    Several commenters had an expansive view of what constitutes 
startup and shutdown. We disagree with these commenters that asserted 
that periods of ``load swings'' should be considered ``startup'' or 
``shutdown,'' as they are generally routine, normal operations with 
production (i.e., generation of electricity) taking place. We maintain 
that the standards as promulgated account for any variability in 
emissions that may occur during these periods over a 30-day averaging 
period, and commenters have provided no data that cause us to doubt 
that determination. We have included definitions of startup and 
shutdown in the final rule that are consistent with the definitions in 
the proposed rule. At proposal, we defined startup as the setting in 
operation of an affected source or portion of an affected source for 
any purpose, and shutdown as the cessation of operation of an affected 
source or portion of an affected source for any purpose.
    Commenters sought more clarity regarding the meaning of these terms 
as applied to EGUs, so we are revising the definitions in the final 
rule as set out in 40 CFR 63.10042.
    These interpretations are tailored for EGUs and are consistent with 
the definitions of ``startup'' and ``shutdown'' contained in the 40 CFR 
part 63, subpart A General Provisions. We believe these revised 
definitions address the comments and are rational based on the fact 
that EGUs function to provide electricity primarily for sale to the 
grid but also at times for use on-site; therefore, EGUs should be 
considered to be operating normally at all times electricity is 
generated. We further believe these revised definitions address what 
some commenters describe as ``warm'' and ``hot'' startups as long as 
the EGU is shutdown (i.e., no fuel fired and no electricity generation) 
prior to the ``warm'' or ``hot'' startup period.
    As for the work practices, in this final rule, the EPA is requiring 
sources to operate using either natural gas or distillate oil for 
ignition during startup. The EPA also is requiring sources to vent 
emissions to the main stack(s) and operate all control devices 
necessary to meet the normal operating standards under this final rule 
(with the exception of dry scrubbers and SCRs) when coal, solid oil-
derived fuel, or residual oil is fired in the boiler during startup or 
shutdown. It is the responsibility of the operators of EGUs to start 
their dry scrubber and SCR systems appropriately to comply with 
relevant standards applicable during normal operation.
    The EPA carefully considered fuels and potential operational 
constraints of air pollution control devices (APCDs) when designing its 
work practices for periods of startup and shutdown. The EPA notes that 
there is no technical barrier to burning natural gas or distillate oil 
for longer portions of startup or shutdown periods, if needed, at a 
boiler, and the HAP emission reduction benefits warrant additional 
utilization of such fuels until the temperature and stack emissions 
pressure is sufficient to engage the APCDs. The EPA is aware that SCR 
systems with ammonia injection need to be operated within a prescribed 
and relatively narrow temperature window to provide NOX 
reductions. Further, the EPA is aware that dry scrubbers also need to 
be operated close to flue gas saturation temperature. Because these 
devices have specific temperature requirements for proper operation, 
the EPA notes in its work practices that it is the responsibility of 
the operators of EGUs to start their SCR and dry scrubber systems 
appropriately to comply with relevant standards applicable during 
normal operation.
    Some commenters have asserted that firing of fuel oil during 
periods of startup and shutdown constrains operation of PM controls 
(ESPs and baghouses) because under cooler conditions, acids and tars 
can condense on surfaces in these controls. The commenters assert that 
such condensation can cause detrimental impacts on hardware and 
operation of these controls, and could cause safety concerns. The EPA 
understands that concerns with acidic and tarry deposits are related to 
firing of heavy (residual) oil and not distillate oil. Accordingly, 
with residual fuel oil firing, site-specific flue gas temperature and 
oxygen (O2) concentration thresholds may be applicable to 
minimize condensation of acids and tars and thereby minimize any 
potential for detrimental impacts on hardware and any safety concerns.

[[Page 9382]]

However, the EPA notes that its work practice requirements provide 
flexibility to the operator to take appropriate site-specific remedial 
measures, if needed. The EPA further notes that boilers have several 
options to prevent detrimental impacts by: (1) Using startup fuels, 
natural gas or distillate oil, until appropriate flue gas conditions 
have been reached and then fire residual oil; (2) pre-coating the PM 
control surfaces \313\ with an alkaline powder (e.g., limestone); (3) 
installing chemically resistant bags \314\ in baghouses if applicable; 
and (4) using low-sulfur oils. The EPA also notes that currently the 
industry has many operational residual oil-fired boilers that are 
started up with either natural gas or distillate fuel oil. At these 
boilers, the transition from the startup fuel, distillate oil or 
natural gas, to residual oil is already being practiced without 
unacceptable impacts on APCDs including PM controls, which are operated 
to meet applicable opacity limits. Based on this experience and the 
options described above, those boilers where residual oil is used for 
either a part of the startup period, or as the main fuel, will also be 
able to operate their PM controls to meet the work practice 
requirements of the rule. Note that coal firing is done at high enough 
temperatures that concerns with condensation are not relevant. None of 
the commenters have specifically commented on this aspect of coal 
firing.
---------------------------------------------------------------------------

    \313\ Coal Power, May 1, 2007: http://www.coalpowermag.com/plant_design/Coal-Plant-O-and-M-River-Locks-and-Barges-Are-an-Aging-Workforce-Too 36.html.
    \314\ Neundorfer: Lesson r, p.4-7, Table 4-1: http://www.neundorfer.com/FileUploads/CMSFiles/Fabric%20Filter%2OMaterial 
[0].pdf.
---------------------------------------------------------------------------

    The EPA is not aware of any operational constraints applicable to 
operation of wet scrubbers during startup that could cause detrimental 
impacts on wet scrubber hardware and safety concerns and none of the 
commenters have commented on this aspect of wet scrubber operation.
    Finally, the EPA notes that dry sorbent injection (DSI) can be 
applied across a very broad temperature range and will be engaged when 
residual oil or coal is fired in a boiler to comply with HCl 
requirements. Again, no comments have been received on this aspect of 
DSI operation.
    This final rule requires work practice standards for emissions 
during startup and shutdown, and the rule requires sources to measure 
and report their emissions at all times, including periods of startup 
and shutdown, when continuous monitoring is used to demonstrate 
compliance. Data collected under this final rule will provide the EPA 
with information to more fully analyze this issue and address it during 
the 8-year review established under CAA section 112.
    We now address malfunctions. In contrast to the exclusion of 
startup and shutdown period emissions from 30-boiler operating day 
rolling average emissions, the final rule requires inclusion of 
emissions during periods of source or APCD malfunction. We have 
concluded that when combined with the availability of an affirmative 
defense as described below, this is an appropriate and practical 
approach.
    As mentioned earlier, periods of startup, normal operations, and 
shutdown are all predictable and routine aspects of a source's 
operations. However, by contrast, malfunction is defined as a ``sudden, 
infrequent, and not reasonably preventable failure of air pollution 
control and monitoring equipment, process equipment or a process to 
operate in a normal or usual manner * * *'' (40 CFR 63.2). The EPA has 
determined that CAA section 112 does not require that emissions that 
occur during periods of malfunction be factored into development of CAA 
section 112 standards. Under CAA section 112, emissions standards for 
new sources must be no less stringent than the level ``achieved'' by 
the best controlled similar source and for existing sources generally 
must be no less stringent than the average emission limitation 
``achieved'' by the best performing 12 percent of sources in the 
category. There is nothing in CAA section 112 that directs the Agency 
to consider malfunctions in determining the level ``achieved'' by the 
best performing or best controlled sources when setting emission 
standards. Moreover, while the EPA accounts for variability in setting 
emissions standards consistent with the CAA section 112 case law, 
nothing in that case law requires the Agency to consider malfunctions 
as part of that analysis. Clean Air Act section 112 uses the concept of 
``best controlled'' and ``best performing'' unit in defining the level 
of stringency that CAA section 112 performance standards must meet. 
Applying the concept of ``best controlled'' or ``best performing'' to a 
unit that is malfunctioning presents significant difficulties, as 
malfunctions are sudden and unexpected events.
    Further, accounting for malfunctions would be difficult, if not 
impossible, given the myriad different types of malfunctions that can 
occur across all sources in the category and given the difficulties 
associated with predicting or accounting for the frequency, degree, and 
duration of various malfunctions that might occur. As such, the 
performance of units that are malfunctioning is not ``reasonably'' 
foreseeable. See, e.g., Sierra Club v. EPA, 167 F. 3d 658, 662 (D.C. 
Cir. 1999) (The EPA typically has wide latitude in determining the 
extent of data-gathering necessary to solve a problem. We generally 
defer to an agency's decision to proceed on the basis of imperfect 
scientific information, rather than to ``invest the resources to 
conduct the perfect study.''). See also, Weyerhaeuser v. Costle, 590 
F.2d 1011, 1058 (D.C. Cir. 1978) (``In the nature of things, no general 
limit, individual permit, or even any upset provision can anticipate 
all upset situations. After a certain point, the transgression of 
regulatory limits caused by `uncontrollable acts of third parties,' 
such as strikes, sabotage, operator intoxication or insanity, and a 
variety of other eventualities, must be a matter for the administrative 
exercise of case-by-case enforcement discretion, not for specification 
in advance by regulation.''). In addition, the goal of a best 
controlled or best performing source is to operate in such a way as to 
avoid malfunctions of the source and accounting for malfunctions could 
lead to standards that are significantly less stringent than levels 
that are achieved by a well-performing non-malfunctioning source. The 
EPA's approach to malfunctions is consistent with CAA section 112, and 
we believe it is a reasonable interpretation of the statute. This 
approach to malfunctions has been used consistently in CAA section 112 
and CAA section 129 rulemaking actions since the D.C. Circuit's 
decision in Sierra Club v. EPA, 551 F.3d 1019 (D.C. Cir. 2008) vacated 
the SSM exemption contained in CFR 63.6(f)(1) and 40 CFR 63.6(h)(1). 
(See, e.g., National Emission Standards for Hazardous Air Pollutants 
From the Portland Cement Manufacturing Industry and Standards of 
Performance for Portland Cement Plants, 75 FR 54970 (September 9, 
2010); Standards of Performance for New Stationary Sources and Emission 
Guidelines for Existing Sources: Sewage Sludge Incineration Units; 
Final Rule, 76 FR 15372 (March 21, 2011).
    In the event that a source fails to comply with the applicable CAA 
section 112(d) standards as a result of a malfunction event, the EPA 
would determine an appropriate response based on, among other things, 
the good faith efforts of the source to minimize emissions during 
malfunction periods, including preventative and corrective actions, as 
well as root cause analyses

[[Page 9383]]

to ascertain and rectify excess emissions. The EPA would also consider 
whether the source's failure to comply with the CAA section 112(d) 
standard was, in fact, ``sudden, infrequent, not reasonably 
preventable'' and was not instead ``caused in part by poor maintenance 
or careless operation.'' 40 CFR 63.2 (definition of malfunction).
    Finally, the EPA recognizes that even equipment that is properly 
designed and maintained can sometimes fail and that such failure can 
sometimes cause an exceedance of the relevant emission standard. (See, 
e.g., State Implementation Plans: Policy Regarding Excessive Emissions 
During Malfunctions, Startup, and Shutdown (Sept. 20, 1999); Policy on 
Excess Emissions During Startup, Shutdown, Maintenance, and 
Malfunctions (Feb. 15, 1983)). The EPA is therefore adding to the final 
rule an affirmative defense to civil penalties for exceedances of 
emission limits that are caused by malfunctions. See 40 CFR 63.10042 
(defining ``affirmative defense'' to mean, in the context of an 
enforcement proceeding, a response or defense put forward by a 
defendant, regarding which the defendant has the burden of proof, and 
the merits of which are independently and objectively evaluated in a 
judicial or administrative proceeding). We also have added other 
regulatory provisions to specify the elements that are necessary to 
establish this affirmative defense; the source must prove by a 
preponderance of the evidence that it has met all of the elements set 
forth in 63.10001. (See 40 CFR 22.24). The criteria ensure that the 
affirmative defense is available only where the event that causes an 
exceedance of the emission limit meets the narrow definition of 
malfunction in 40 CFR 63.2 (i.e., sudden, infrequent, not reasonable 
preventable and not caused by poor maintenance and or careless 
operation). For example, to assert the affirmative defense 
successfully, the source must prove by a preponderance of the evidence 
that excess emissions ``[w]ere caused by a sudden, infrequent, and 
unavoidable failure of air pollution control and monitoring equipment, 
process equipment, or a process to operate in a normal or usual manner 
* * *'' The criteria also are designed to ensure that steps are taken 
to correct the malfunction, to minimize emissions in accordance with 
section 63.10001 and to prevent future malfunctions. For example, the 
source must prove by a preponderance of the evidence that ``[r]epairs 
were made as expeditiously as possible when the applicable emission 
limitations were being exceeded * * *'' and that ``[a]ll possible steps 
were taken to minimize the impact of the excess emissions on ambient 
air quality, the environment and human health * * *'' In any judicial 
or administrative proceeding, the Administrator may challenge the 
assertion of the affirmative defense and, if the respondent has not met 
its burden of proving all of the requirements in the affirmative 
defense, appropriate penalties may be assessed in accordance with CAA 
section 113 (see also 40 CFR 22.27).
    The EPA is including an affirmative defense in the final rule as we 
have in other recent MACT rules so as to balance the tension, inherent 
in many types of air regulation, to ensure adequate compliance while 
simultaneously recognizing that despite the most diligent of efforts, 
emission limits may be exceeded under circumstances beyond the control 
of the source. The EPA must establish emission standards that ``limit 
the quantity, rate, or concentration of emissions of air pollutants on 
a continuous basis.'' 42 U.S.C. 7602(k) (defining ``emission limitation 
and emission standard''). See generally Sierra Club v. EPA, 551 F.3d 
1019, 1021 (D.C. Cir. 2008). Thus, the EPA is required to ensure that 
section 112 emissions limitations are continuous. The affirmative 
defense for malfunction events meets this requirement by ensuring that 
even where there is a malfunction, the emission limitation is still 
enforceable through injunctive relief. While ``continuous'' 
limitations, on the one hand, are required, there is also case law 
indicating that in some situations it is appropriate for the EPA to 
account for the practical realities of technology. For example, in 
Essex Chemical v. Ruckelshaus, 486 F.2d 427, 433 (D.C. Cir. 1973), the 
D.C. Circuit acknowledged that in setting standards under CAA section 
111 ``variant provisions'' such as provisions allowing for upsets 
during startup, shutdown and equipment malfunction ``appear necessary 
to preserve the reasonableness of the standards as a whole and that the 
record does not support the `never to be exceeded' standard currently 
in force.'' See also, Portland Cement Association v. Ruckelshaus, 486 
F.2d 375 (D.C. Cir. 1973). Though intervening case law such as Sierra 
Club v. EPA and the CAA 1977 amendments calls into question the 
relevance of these cases today, they support the EPA's view that a 
system that incorporates some level of flexibility is reasonable. The 
affirmative defense simply provides for a defense to civil penalties 
for excess emissions that are proven to be beyond the control of the 
source. By incorporating an affirmative defense, the EPA has formalized 
its approach to upset events. In a Clean Water Act setting, the Ninth 
Circuit required this type of formalized approach when regulating 
``upsets beyond the control of the permit holder.'' Marathon Oil Co. v. 
EPA, 564 F.2d 1253, 1272-73 (9th Cir. 1977). But see, Weyerhaeuser Co. 
v. Costle, 590 F.2d 1011, 1057-58 (D.C. Cir. 1978) (holding that an 
informal approach is adequate). The affirmative defense provisions give 
the EPA the flexibility to ensure both that its emission limitations 
are ``continuous'' as required by 42 U.S.C. 7602(k), and account for 
unplanned upsets and thus support the reasonableness of the standard as 
a whole.

F. Testing and Initial Compliance

    We have carefully evaluated the wide-ranging comments on testing, 
continuous monitoring, and other provisions regarding initial 
compliance demonstrations, and we have made adjustments intended to 
help streamline implementation while still ensuring adequate 
demonstration of compliance with the emission limits and other 
standards established under this final rule. The significant changes 
include:
1. No Fuel Analysis Requirements
    Apart from an alternative that allows you to analyze fuel moisture 
for liquid oil-fired EGUs rather than measuring HCl and HF, the final 
rule does not include any of the fuel analysis requirements that were 
in the proposed rule, either as part of initial compliance 
demonstrations or ongoing compliance demonstrations. In reviewing the 
results of the fuel analyses and the expected range of results that 
would be received from laboratories conducting the proposed analyses, 
we determined that too many results would be returned as ``below 
detection level'' and, thus, provide little information to assist with 
rule implementation and compliance oversight. Given the costs and 
efforts involved, we determined that the proposed fuel analysis 
requirements would not be an effective compliance monitoring tool for 
this final rule.
2. Clarification of Testing
    We have clarified that where options for emission limits apply 
(such as filterable PM versus non-mercury HAP metals, or SO2 
versus HCl), you need only perform stack testing to demonstrate 
compliance with the selected emission limit. For example, if you elect 
to meet the individual non-

[[Page 9384]]

mercury HAP metals standards, you must conduct the Method 29 test for 
the metals, and you do not have to conduct a Method 5 test for PM.
3. Low Emitting EGU Qualification
    We have significantly modified the proposed requirements to qualify 
as a LEE unit for a pollutant other than Hg based on an initial 
performance test. Under the proposed rule, the operating limit 
monitoring provided additional assurance of compliance for a source 
qualified for non-mercury LEE status based on an initial compliance 
demonstration. Under the final rule, to qualify for LEE status for 
pollutants other than Hg, a unit must meet the LEE criteria for a 
series of performance tests over a 3-year period to demonstrate that 
the unit continues to perform well below the standard for which the 
source has obtained LEE status.

G. Continuous Compliance

    The most significant changes to the testing and monitoring 
requirements involve the procedures for demonstrating continuous 
compliance. The proposed rule contained different options involving 
CEMS, periodic stack tests, fuel analysis, and various PM and control 
device operating limits. The final rule greatly simplifies the 
requirements and provides two basic approaches for most situations: use 
of continuous monitoring (either CEMS or PM continuous parametric 
monitoring system, CPMS) or periodic quarterly testing. The final rule 
does not contain the proposed fuel analysis requirements. For periodic 
testing, the proposed rule required testing every month or every 2 
months. For those EGU owners or operators who choose to use emissions 
testing to demonstrate compliance, the final rule requires quarterly 
filterable PM or non-mercury metals HAP, whether individual or total 
metals, testing for coal- and liquid oil-fired units. The rule requires 
quarterly HCl testing for coal-fired units and quarterly HCl and HF 
testing, along with site-specific monitoring for liquid oil-fired units 
to ensure compliance with the HCl and HF standards. The final rule also 
has a separate compliance demonstration for those liquid oil-fired EGUs 
that have an annual capacity factor of less than 8 percent (emission 
limits do not apply, just the tune-up work practice standard). For 
those EGU owners or operators who choose to use emissions testing to 
demonstrate compliance, the final rule requires quarterly filterable PM 
or non-mercury metals HAP, whether individual or total metals, testing 
for coal- and liquid oil- fired units; quarterly HCl testing for coal-
fired units and quarterly HCl and HF testing, along with site-specific 
parameter monitoring for liquid oil-fired units to ensure compliance 
with the HCl and HF standards.
    The continuous monitoring options remain generally intact from the 
proposed rule, with relatively minor clarifications concerning 
calculation of 30-boiler operating day averages and QA requirements.
    The final rule eliminates all operating limits for PM except for 
the use of a PM CPMS. For the PM CPMS, the final rule clarifies 
procedures for setting this operating limit and how it is distinct from 
the PM emission limit. The PM CPMS will not be correlated as a PM CEMS 
under PS 11 and will produce data in terms of a signal you define. That 
signal could be milliamps, stack concentration, or other output signal 
instead of PM emissions in units of the standard. The operating limit 
will be set using the highest hourly average obtained from the PM CPMS 
during the performance test. Compliance with the limit is based on a 
30-boiler operating day rolling average basis. However, the final rule 
also does provide for the use of a PM CEMS to determine compliance with 
the filterable PM emission limit if the source elects to use this 
approach. The EPA believes that some sources may be interested in 
adopting this direct approach, and so has included that option in the 
final rule. If this approach is selected, the PM CEMS is used as the 
direct method of compliance and no additional testing is required other 
than tests that are required as part of the QA requirements in PS 11 
and Procedure 2. To use this option, the source must elect to meet the 
filterable PM standard, and not one of the HAP metals standards.
    Apart from the operating limit for site-specific monitoring 
associated with liquid oil-fired EGUs, we removed the other operating 
limits for control devices based on a review of the comments, after 
considering other programs in place to ensure proper operations of 
controls at EGUs. Those other programs include compliance assurance 
monitoring under part 64, part 70, and New Source Review permit 
conditions, and other SIP and NSPS requirements for operating and 
maintaining equipment in accordance with good air pollution control 
practices. Those requirements, in combination with the CEMS, PM CPMS, 
and frequent periodic testing provisions under the final rule, will 
enhance the monitoring of continuous compliance with the requirements 
of this rule.
    Because the EPA is concerned that there will be little or no 
monitoring in these underlying applicable requirements for acid gases 
at liquid oil-fired EGUs, the final rule requires a site-specific 
monitoring plan for those units in this subcategory that demonstrate 
compliance with the HCl and HF standards through quarterly performance 
tests. With the exception for limited-use liquid oil-fired EGUs and 
other monitoring options available (such as fuel moisture monitoring or 
HCl/HF CEMS), the EPA believes this provision will apply to few units. 
The owner or operator will submit the site-specific plan to identify 
appropriate parameters that ensure that the operations of the unit 
critical to meeting the HCl/HF emission limits remain consistent with 
conditions during performance testing. This will be approved similarly 
to an alternative monitoring request. The plan should include the 
parameters, monitoring approach, QA/QC elements, and data reduction 
(including averaging period) elements. Like the PM CPMS operating 
limit, the operating limit for acid gas control devices on liquid oil-
fired EGUs will be set using the highest hourly average obtained during 
the HCl and HF performance tests. Compliance with the limit is based on 
a 30-boiler operating day rolling average basis.
    Finally, we have changed the continuous compliance requirements for 
the performance tune-up work practice standard since the proposal. Our 
intent was that this work practice standard could be performed in 
conjunction with routine maintenance operations at a facility and be a 
logical extension of routine best practices for boiler inspection and 
optimization. Based on the comments received, we have reduced the 
required frequency for this inspection to every 3 years and provided 
incentives for neural network combustion management and optimization 
practices by providing a longer interval of 4 years between inspections 
when such systems are in use at a given EGU.

H. Emissions Averaging

    We are finalizing that owners and operators of existing affected 
sources may demonstrate compliance by emissions averaging for existing 
EGUs that are located at the same facility that are within a single 
subcategory and that rely on emissions testing as the compliance 
demonstration method. In response to our request for comments on the 
suitability of emissions averaging and need for a discount factor, we 
received a range of suggestions, including requests for clarification 
regarding eligibility, points for and against the need for a discount 
factor, and suggestions to ease implementation.

[[Page 9385]]

    As we noted at proposal, part of the EPA's general policy of 
encouraging the use of flexible compliance approaches where they can be 
properly monitored and enforced is to include emissions averaging. 
Emissions averaging can provide sources the flexibility to comply in 
the least costly manner while still maintaining a regulation that is 
workable and enforceable. Emissions averaging would not be applicable 
to new affected sources and could only be used between EGUs in the same 
subcategory at a particular facility. Also, owners or operators of 
existing sources subject to the EGU NSPS (40 CFR part 60, subparts D 
and Da) would be required to continue to meet the PM emission standard 
of that NSPS regardless of whether or not they are using emissions 
averaging (i.e., an EGU subject to 40 CFR part 60, subpart D or Da must 
meet its applicable NSPS filterable PM emission limit even if it is 
included in a 40 CFR part 63, subpart UUUUU, emissions averaging group 
for filterable PM).
    Emissions averaging allows owners and operators of a facility that 
includes existing EGUs within a subcategory to demonstrate that the 
source complies with the proposed emission limits by averaging the 
emissions from an individual affected EGU that is emitting above the 
proposed emission limits with other affected EGUs at the same facility 
that are emitting below the proposed emission limits and that are 
within the same subcategory. Although some commenters note that the 
MACT limits are low, based on the data available to the Agency, we 
believe that dozens of existing EGUs are achieving all of the limits 
and, thus, emissions averaging is a possible approach.
    The final rule includes an emissions averaging compliance 
alternative because emissions averaging \315\ represents an equivalent, 
more flexible, and less costly alternative to controlling certain 
emission points to MACT levels. We have concluded that averaging in the 
proposed rule could be implemented and that it would not lessen the 
stringency of the MACT floor limits and would provide flexibility in 
compliance, cost and energy savings to owners and operators. We also 
recognize that we must ensure that any emissions averaging option can 
be implemented and enforced, will be clear to sources, and most 
importantly, will be no less stringent than unit-by-unit implementation 
of the MACT floor limits.
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    \315\ As long as required emission rates are designed to account 
for factors such as changes in averaging times.
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    In the final rule, the EPA is providing that sources may average 
emissions from existing EGUs at the same facility and within the same 
subcategory. Further, for Hg emissions only from existing EGUs within 
the same subcategory, such EGUs in an emissions averaging plan may use 
an alternate compliance approach consisting of a 90-boiler operating 
day rolling average emission limit of 1.0 lb/TBtu or 1.1E-2 lb/GWh.
    In the memo entitled ``The Impact of Emission Averaging Time on the 
Stringency of an Emission Standard'' in the docket, we have illustrated 
why a longer-term average results in a lower limit. In essence, longer-
term averages allow particularly high (or low) measurements to be 
averaged with many more measurements closer to the mean. This results 
in the highest averages from a longer-term averaging period (e.g., 90 
days) being lower than the highest averages in a shorter term averaging 
period (e.g., 30 days).
    We have illustrated this concept by taking Hg CEMS data and 
calculating rolling 30-day averages and rolling 90-day averages. The 
30-day averages have greater variability and, thus, higher peaks and 
valleys. The 90-day average has less variability; therefore, the same 
unit is able to meet a tighter 90-day limit.
    The EPA is providing this alternate 90-day rolling average 
compliance approach for Hg only. A 90-day rolling average is 
appropriate for Hg, and only for Hg, because the health and 
environmental impacts associated with Hg are related to environmental 
loading rather than shorter term inhalation or other acute exposure, as 
is the case with HCl and PM. We believe that this alternative 
compliance approach will provide at least the same level of 
environmental protection while allowing companies greater flexibility 
to use emissions averaging. For example, such an approach would allow 
for the averaging of an infrequently operated unit that is operating 
slightly above the standard with a more frequently operated unit that 
is operating below the standard in the instances when the more 
frequently operated unit is in a multi-day or multi-week maintenance 
outage.
    The EPA has concluded that it is permissible to establish within a 
NESHAP a unified compliance regimen that permits averaging within the 
same facility across individual existing EGUs subject to the same 
standards under certain conditions. As mentioned earlier, individual 
EGUs within an emissions averaging group would be allowed to have 
emissions greater than, less than, or equivalent with the emissions 
limit for their subcategory, provided that the average emissions 
comprised from individual EGU emissions do not exceed the emissions 
limit for their subcategory. Averaging across affected units is 
permitted only if it can be demonstrated that the total quantity of any 
particular HAP that may be emitted by that portion of a contiguous 
major source that is subject to the same standards in the NESHAP will 
not be greater under the averaging mechanism than it could be if each 
individual affected EGU in the subcategory complied separately with the 
applicable standard. Under this test, the practical outcome of 
averaging is equivalent to compliance with the MACT floor limits by 
each discrete EGU, and the statutory requirement that the MACT standard 
reflect the maximum achievable emissions reductions is, therefore, 
fully effectuated.
    As noted in the proposal preamble, in past rulemakings, the EPA has 
generally imposed certain limits on the scope and nature of emissions 
averaging programs. These limits include: (1) No averaging between 
different types of pollutants; (2) No averaging between sources that 
are not part of the same affected source; (3) No averaging between 
individual sources within a single major source if the individual 
sources are not subject to the same NESHAP; and (4) No averaging 
between existing sources and new sources.
    The final rule fully satisfies each of these criteria. First, 
emissions averaging would only be permitted between individual existing 
sources at a single stationary source (i.e., the facility), and would 
only be permitted between individual sources in the same subcategory in 
the final EGU NESHAP. Further, emissions averaging would not be 
permitted between two or more different affected sources. Finally, new 
affected sources could not use emissions averaging. Accordingly, we 
have concluded that the averaging of emissions across affected units in 
the same existing source subcategory is consistent with the CAA. In 
addition, the final rule requires each facility that intends to utilize 
emissions averaging to develop an emissions averaging plan, which 
provides additional assurance that the necessary criteria will be 
followed. In this emissions averaging plan, the facility must include 
the identification of: (1) All units in the averaging group; (2) the 
control technology installed; (3) the process parameter that will be 
monitored; (4) the specific control technology or pollution

[[Page 9386]]

prevention measure to be used; (5) the test plan for the measurement of 
the HAP being averaged; and (6) the operating parameters to be 
monitored for each control device. A state, local, or tribal regulatory 
agency that is delegated authority for this rule could require the 
emissions averaging plan to be submitted or even approved before 
emissions averaging could be used. Upon receipt, the regulatory 
authority would not be able to approve an emissions averaging plan 
differing from the eligibility criteria contained in the rule.
    The final rule excludes new affected sources from the emissions 
averaging provision. The EPA does not believe the statute authorizes 
emissions averaging for new affected sources. One reason we allow 
emissions averaging is to give existing sources flexibility to achieve 
compliance at diverse points with varying degrees of add-on control 
already in place in the most cost-effective and technically reasonable 
fashion.
    With the monitoring and compliance provisions that are being 
finalized, there is additional assurance that the environmental benefit 
will be realized. Further, the emissions averaging provision would not 
apply to individual EGUs if the EGU shares a common stack with units in 
other subcategories, because in that circumstance it is not possible to 
distinguish the emissions from each individual unit.\316\
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    \316\ The EPA has reviewed monitoring data submitted to the 
Agency under the Title IV Acid Rain Program. Based on that review, 
the EPA is unaware of any coal- and oil-fired units that share a 
common stack.
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    The rule allows EGUs that rely on CEMS for compliance 
demonstrations to be able to participate in emissions averaging and the 
emissions limits are not subject to a discount. The EPA believes that 
the data certainty provided by units that use CEMS would be ideal for 
emissions averaging and the flexibility and cost-effectiveness it 
offers. Given the homogeneity of fuels within the rules subcategories, 
along with other emissions averaging criteria, the Agency believes use 
of a discount factor to be unwarranted for this rule.
    The emissions averaging provisions in this final rule are based in 
part on the emissions averaging provisions in the Hazardous Organic 
NESHAP (HON). The legal basis and rationale for the HON emissions 
averaging provisions were provided in the preamble to the final 
HON.\317\ We do not believe that we have the authority to provide for 
emissions averaging among EGUs in different subcategories or among EGUs 
not physically located at the same affected facility.
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    \317\ Hazardous Organic NESHAP (59 FR 19,425; April 22, 1994).
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I. Notification, Recordkeeping, and Reporting

    Compared to the proposed rule, the reduced continuous compliance 
requirements in the final rule--primarily reduced testing frequencies 
and removal of fuel analyses and control device or fuel operating 
parameter monitoring--considerably reduces the overall burden 
associated with recordkeeping and reporting. Based on evaluation of the 
comments received, we have established a provision in the final rule 
for submission of most CEMS data (including monitoring plan, emissions 
data, and QA data) through ECMPS, so that the affected industry uses a 
common reporting tool for submitting CEMS data.
    For data other than most CEMS data, the final rule requires 
electronic reporting of certain data, including performance test 
reports, PM CPMS data, PM CEMS data, and, if approved as part of an 
alternative monitoring request, HAP metals CEMS data. Other reports, 
such as notifications, must be submitted in hard copy format or in 
accordance with the procedures established by state and local agencies 
that receive delegation for implementing this rule. In the proposed 
rule, we took comment on these approaches and stated our anticipation 
of adopting these approaches. In the final rule, we have extended the 
ECMPS reporting to most CEMS data to promote harmonization for CEMS 
data from the industry, while leaving reporting of non-CEMS data in a 
separate reporting system.

J. Technical/Editorial Corrections

    In this final action, we are making a number of technical 
corrections and clarifications to 40 CFR part 63, subpart UUUUU. These 
changes clarify procedures for implementing the emission limitations 
for affected sources. We are also clarifying several definitions to 
help affected sources determine applicability of this rule. We have 
modified some proposed regulatory language based on public comments. In 
addition, in response to comments received (including the May 2010 
notice from the Utility Air Regulatory Group (UARG) of calculation 
errors in the proposed Hg MACT floor limits), we have checked all 
calculations and made corrections where necessary.
    In several places throughout the subpart, including the associated 
tables, we have corrected the cross-references to other sections and 
paragraphs of the subpart.

VII. Public Comments and Responses to the Proposed NESHAP

A. MACT Floor Analysis

1. New Data/Technical Corrections to Old Data
    Comment: Many commenters identified errors in the emissions 
database compiled through information provided by industry in response 
to the 2010 information collection request (ICR) that supported 
development of this rule. Commenters submitted corrections to the EPA 
during the public comment period.
    Response: The EPA has incorporated technical corrections and new 
data submitted prior to the end of the comment period. The corrections 
and new data are described in detail in a memorandum in the docket. The 
EPA re-ranked the sources in the MACT floor pools to the extent 
necessary based on the new or corrected data, and we recalculated the 
MACT floors as necessary based on the re-ranking of sources. The 
revised MACT floors were established using the same methodology set 
forth in the proposed rule.
2. Pollutant-by-Pollutant Approach
    Comment: Many commenters raised concerns about the way the EPA 
determined the MACT floors using a pollutant-by-pollutant approach. 
Commenters contended that such a methodology produced limits that are 
not achievable in combination, and as such, the limits do not comport 
with the intent of the statute or the recent court decision (NRDC v. 
EPA, 2007). Commenters further added that the CAA directs the EPA to 
set standards based on the overall performance of ``sources'' and CAA 
sections 112(d)(1), (2), and (3) specify that emissions standards be 
established on the ``in practice'' performance of a ``source'' in the 
category or subcategory. Commenters stated that if Congress had 
intended for the EPA to establish MACT floor levels considering the 
achievable emission limits of individual HAP, it could have worded CAA 
section 112(d)(3) to refer to the best-performing sources ``for each 
pollutant.'' Many commenters added that the EPA's discretion in setting 
standards is limited to distinguishing among classes, types, and sizes 
of sources. Commenters contend that although Congress limited the EPA's 
authority to parse units and sources with similar design and types, it 
does not allow the EPA to ``distinguish'' units and sources by 
individual pollutant as proposed in this rule (Sierra Club v. EPA, 551 
F.3d 1019, 1028 (D.C. Cir. 2008)). By calculating each MACT floor

[[Page 9387]]

independently of the other pollutants, commenters contend that the 
combination of HAP limits results in a set of standards that only a 
hypothetical ``best performing'' unit could achieve.
    Response: We disagree with the commenters who believe MACT floors 
cannot be set on a pollutant-by pollutant basis. Contrary to the 
commenters' suggestion, CAA section 112(d)(3) does not mandate a total 
facility approach. A reasonable interpretation of CAA section 112(d)(3) 
is that MACT floors may be established on a HAP-by-HAP basis, so that 
there can be different pools of best performers for each HAP. Indeed, 
as illustrated below, the total facility approach not only is not 
compelled by the statutory language but can lead to results so 
arbitrary that the approach may simply not be legally permissible.
    Clean Air Act section 112(d)(3) is not explicit as to whether the 
MACT floor is to be based on the performance of an entire source or on 
the performance achieved in controlling particular HAP. Congress 
specified in CAA section 112(d)(3) the minimum level of emission 
reduction that could satisfy the requirement to adopt MACT. For new 
sources, this floor level is to be ``the emission control that is 
achieved in practice by the best controlled similar source.'' For 
existing sources, the floor level is to be ``the average emission 
limitation achieved by the best performing 12 percent of the existing 
sources'' for categories and subcategories with 30 or more sources, or 
``the average emission limitation achieved by the best performing 5 
sources'' for categories and subcategories with fewer than 30 sources. 
Commenters point to the statute's reference to the best performing 
``sources,'' and claim that Congress would have specifically referred 
to the best performing sources ``for each pollutant'' if it intended 
for the EPA to establish MACT floors separately for each HAP.
    The EPA disagrees. The language of the Act does not address whether 
floor levels can be established HAP-by-HAP or by any other means. The 
reference to ``sources'' does not lead to the assumption the commenters 
make that the best performing sources can only be the best-performing 
sources for the entire suite of regulated HAP. Instead, the language 
can be reasonably interpreted as referring to the source as a whole or 
to performance as to a particular HAP. Similarly, the reference in the 
new source MACT floor provision to ``emission control achieved by the 
best controlled similar source'' can mean emission control as to a 
particular HAP or emission control achieved by a source as a whole.
    Commenters also stressed that CAA section 112(d) requires that 
floors be based on actual performance from real facilities. The EPA 
agrees that this language refers to sources' actual operation, but 
again the language says nothing about whether it is referring to 
performance as to individual HAP or to single facility's performance 
for all HAP. Industry commenters also said that Congress could have 
mandated a HAP-by-HAP result by using the phrase ``for each HAP'' at 
appropriate points in CAA section 112(d). The fact that Congress did 
not do so does not compel any inference that Congress was sub-silentio 
mandating a different result when it left the provision ambiguous on 
this issue. The argument that MACT floors set HAP-by-HAP are based on 
the performance of a hypothetical facility, so that the limitations are 
not based on those achieved in practice, just reiterates the question 
of whether CAA section 112(d)(3) refers to whole facilities or 
individual HAP. All of the limitations in the floors in this rule 
reflect sources' actual performance and were achieved in practice. As 
to commenters' claims that standards set in this manner cannot be met 
by any actual sources, we have determined that there are approximately 
69 existing coal-fired EGUs that meet all of the final existing source 
MACT emission limits (out of 252 EGUs that reported data for Hg, PM, 
and HCl in the 2010 ICR) and at least one EGU that meets all of the 
final new source MACT emission limits.
    Commenters also point to the EPA's subcategorization authority, and 
claim that because Congress authorized the EPA to distinguish among 
classes, types, and sizes of units, the EPA cannot distinguish units by 
individual pollutant, as they allege the EPA did in the proposed rule. 
However, that statutory language addresses the EPA's authority to 
subcategorize sources within a source category prior to setting 
standards, which the EPA has done for certain EGUs. The EPA is not 
distinguishing within each subcategory based on HAP emitted. Rather, it 
is establishing emissions standards based on the emissions limits 
achieved by units in each subcategory. Therefore, the EPA's 
subcategorization authority is irrelevant to the question of how the 
EPA establishes MACT floor standards once it has made the decision to 
distinguish among sources and create subcategories.
    The EPA's long-standing interpretation of the Act is that the 
existing and new source MACT floors are to be established on a HAP-by-
HAP basis. One reason for this interpretation is that a whole plant 
approach could yield least common denominator floors--that is, floors 
reflecting limited or no control, rather than performance which is the 
average of what best performers have achieved. See 61 FR 173687 (April 
19, 1996); 62 FR 48363-64 (September 15, 1997) (same approach adopted 
under the very similar language of CAA section 129(a)(2)). Such an 
approach would allow the performance of sources that are outside of the 
best-performing 12 percent for certain pollutants to be included in the 
floor calculations for those same pollutants, and it is even 
conceivable that the worst performing source for a pollutant could be 
considered a best performer overall, a result Congress could not have 
intended. Inclusion of units that are outside of the best performing 12 
percent for particular pollutants would lead to emission limits that do 
not meet the requirements of the statute.
    For example, if the best performing 12 percent of facilities for 
HAP metals were also the worst performing units for acid gas HAP and 
the best performers for acid gas HAP were the worst performers for HAP 
metals, the floor for acid gases or metals would end up not reflecting 
best performance. In such a situation, the EPA would have to make a 
value judgment as to which pollutant reductions were most critical to 
decide which sources are best controlled.\318\ Such value judgments are 
antithetical to the direction of the statute at the MACT floor-setting 
stage.
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    \318\ See Petitioners Brief in Medical Waste Institute et al. v. 
EPA, No. 09-1297 (D.C. Cir.) pointing out, in this context, that 
``the best performers for some pollutants are the worst performers 
for others'' (p. 34) and ``[s]ome of the best performers for certain 
pollutants are among the worst performers for others.''
---------------------------------------------------------------------------

    Commenters suggested that a multi-pollutant approach could be 
implemented by weighting pollutants according to relative toxicity and 
calculating weighted emissions totals to use as a basis for identifying 
and ranking best performers. This suggested approach would require the 
EPA to essentially prioritize the regulated HAP based on relative risk 
to human health of each pollutant, where risk is a criterion that has 
no place in the establishment of MACT floors, which are required by 
statute to be based on technology.
    The central purpose of the amended air toxics provisions was to 
apply strict technology-based emission controls on HAP. See, e.g., H. 
Rep. No. 952, 101st Cong. 2d sess. 338. An interpretation that the 
floor level of control must be limited by the performance of devices

[[Page 9388]]

that only control some of these pollutants effectively guts the 
standards by including worse performers in the averaging process, 
whereas the EPA's interpretation promotes the evident Congressional 
objective of having the floor reflect the average performance of best 
performing sources. Because Congress has not spoken to the precise 
question at issue, and the Agency's interpretation effectuates 
statutory goals and policies in a reasonable manner, its interpretation 
must be upheld. See Chevron v. NRDC, 467 U.S. 837 (1984).\319\
---------------------------------------------------------------------------

    \319\ Because industry commenters argued that the statute can 
only be read to allow floors to be determined on a single source 
basis, commenters offered no view of why their reading could be 
viewed as reasonable in light of the statute's goals and objectives. 
It is not evident how any statutory goal is promoted by an 
interpretation that allows floors to be determined in a manner 
likely to result in floors reflecting emissions from worst or 
mediocre performers.
---------------------------------------------------------------------------

    The EPA notes, however, that if optimized performance for different 
HAP is not technologically possible due to mutually inconsistent 
control technologies (for example, if metals performance decreased as 
organics reduction is optimized), then this would have to be taken into 
account by the EPA in establishing a floor (or floors). The Senate 
Report indicates that if certain types of otherwise needed controls are 
mutually exclusive, the EPA is to optimize the part of the standard 
providing the most environmental protection. S. Rep. No. 228, 101st 
Cong. 1st sess. 168 (although, as noted, the bill accompanying this 
Report contained no floor provisions). It should be emphasized, 
however, that the D.C. Circuit has stated that ``the fact that no plant 
has been shown to be able to meet all of the limitations does not 
demonstrate that all the limitations are not achievable.'' Chemical 
Manufacturers Association v. EPA, 885 F. 2d at 264 (upholding 
technology-based standards based on best performance for each pollutant 
by different plants, where at least one plant met each of the 
limitations but no single plant met all of them).
    All available data for EGUs indicate that there is no technical 
problem achieving the floor levels contained in this final rule for 
each HAP simultaneously, using the MACT floor technology. Data 
demonstrating a technical conflict in meeting all of the limits have 
not been provided, and, as stated above, based on the available data, 
there are approximately 64 EGUs that meet all of the final existing 
source emission limits and at least one EGU that meets all of the final 
new source emission limits.
3. Minimum Number of EGUs To Set Floors
    Comment: Many commenters indicated that CAA section 112 requires 
that data from a minimum of 5 units are required to set MACT floors for 
existing sources. Commenters noted that the EPA's use of less than 5 
units for subcategories with greater than 30 units is a legalistic 
reading of CAA section 112 that could result in such absurd results as 
using 5 units to set MACT floors for a subcategory with 29 units and 
data for only 10 units, but using a single unit to set MACT floors for 
a subcategory with 31 units and data for only 10 units.
    Response: The EPA does not agree that CAA section 112(d)(3) 
mandates a minimum of 5 sources in all instances, notwithstanding the 
incongruity of having less data to establish floors for larger source 
categories than is mandated for smaller ones. The literal language of 
the provision appears to compel this result. CAA section 112(d)(3) 
states that for categories and subcategories with at least 30 sources, 
the MACT floor for existing sources shall be no less stringent than the 
average emission limitation achieved by the best-performing 12 percent 
of the sources for which the Administrator has emissions information. 
The plain language of this provision requires the use of fewer data 
points for large source categories than for small source categories 
where the Administrator only has emissions information on a small 
number of units for categories and subcategories with 30 or more 
sources. Furthermore, commenters contend that Congress could not have 
intended the floors for a subcategory with 29 sources to be based on 5 
sources and a subcategory with 31 sources to be based on less than that 
number; but we maintain this contention is without merit because 12 
percent of 31 is 3.72 (rounded to 4) so the EPA would not base 
standards for a subcategory with 31 sources on 5 sources even if we had 
data on all 31 sources in the subcategory. For these reasons, we 
decline to adopt commenters' position and continue to adhere to the 
clear statutory directive.
4. Treatment of Detection Levels
    Comment: Commenters stated that when setting the MACT floors, non-
detect values are present in many of the datasets from best performing 
units. Commenters provided input on how these non-detect values should 
be treated in the MACT floor analysis. Some commenters agreed that it 
is appropriate to keep the detection levels as reported, while certain 
commenters suggested that the detection levels should be replaced using 
a value of half the method detection limit (MDL). Many other commenters 
stated that data that are below the detection limit should not be used 
in setting the floors, and these data should be replaced with a higher 
value including either the MDL, limit of quantitation (LOQ), practical 
quantitation limit (PQL), or reporting limit (RL) for the purposes of 
the MACT floor calculations. Other commenters stated all non-detect 
values should be excluded from the floor analysis, or all values should 
be treated as zero.
    Some commenters stated it is necessary to keep the data as reported 
because changing values would lead to an upward bias. Additional 
commenters agreed with this basic premise, but suggested that replacing 
non-detect data with a value of half the MDL is appropriate while still 
minimizing the bias. They noted that treating measurements below the 
MDL as occurring at the MDL is statistically incorrect and violates the 
statute's ``shall not be less stringent than'' requirement for MACT 
floors. One commenter also provided a reference for a statistical 
method based on a log-normal distribution of the data which estimated 
the ``maximum likelihood'' of data values; this result is slightly 
higher than half the MDL.
    Some commenters stated that it is necessary to substitute the MDL 
value when performing the MACT floor calculations. With MDL defined as 
the lowest concentration that can be distinguished from the blank at a 
defined level of statistical significance, this is an appropriate 
value. If MDL values are not reported, one commenter suggested an 
approach for estimating an MDL equivalent value, but recognized that 
the background laboratory and test report files may not be available to 
the EPA in order to derive these estimates.
    Most commenters representing industry and industry trade groups 
argued that either LOQ or PQL values should replace non-detects. The 
LOQ is defined as the smallest concentration of the analyte which can 
be measured. These commenters contended that the LOQ leads to a 
quantifiable amount of the substance with an acceptable level of 
uncertainty. A few commenters provided calculations showing some of the 
proposed MACT floors were below the LOQ. Additionally, some of these 
commenters stated that using LOQ or PQL values also incorporates 
additional sources of random and inherent sampling error throughout the 
testing process, which is necessary. These errors occur during sample 
collection, sample recovery, and sample analysis;

[[Page 9389]]

MDL values only account for method specific (e.g., instrument) errors. 
These commenters contended that the three times the MDL approach 
discussed in the proposal accounts for some measurement errors but does 
not account for these unavoidable sampling errors. The commenters also 
noted that an LOQ is calculated as 3.18 times the MDL, and PQL is 
calculated as 5 to 10 times the MDL. Many of the commenters in support 
of using either an LOQ or PQL value ultimately believed a work practice 
is more appropriate where a MACT floor limit is below either of these 
two values. They cited CAA section 112(h)(1) which allows work 
practices under CAA section 112(h)(2) if ``the application of 
measurement methodology to a particular class of sources is not 
practicable due to technological and economic limitations''. These 
commenters stated that the inability of sources to accurately measure a 
pollutant at the level of the MACT floor qualifies as such a 
technological limitation that warrants a work practice standard.
    Commenters stated that where the proposed MACT floor is below the 
LOQ or PQL then that source category has a technological measurement 
limitation. A few commenters suggested RL values should be used when 
developing the floor limits. They stated that the RL is the lowest 
level at which the entire analytical system gives reliable signals and 
includes an acceptable calibration point. They added that use of an 
acceptable calibration point is critical in showing that numbers are 
real versus multiplying the MDL by various factors.
    Several commenters stated that all non-detect values should be 
excluded from MACT floor calculations. They believed that excluding all 
non-detect values would eliminate any potential errors or accuracy 
issues related to testing for compliance. Due to inconsistencies of the 
MDL value reported for non-detect data, one commenter suggested 
treating all such values as zero. This would provide a consistent 
approach for setting the floor as well as determining compliance.
    Several commenters provided input on the EPA's proposed method of 
three times the MDL as an option for setting limits. A few commenters 
in support noted that this approach provided a reasonable method to 
account for data variability as it took into account more than just 
analytical instrument precision. Many other commenters argued that this 
method results in limits which are too low, namely that it is still 
lower than the LOQ value which they are in favor of as a substitute for 
any reported non-detect data. Other commenters disagreed with this 
method and claimed that it would lead to results which introduce a high 
bias in the floor setting process. A few contended that multiplying by 
3 would introduce a 300 percent error into the floor, resulting in a 
floor that is less stringent than required by the Act. Others suggested 
that the MDL values are antiquated and already too high and thus it is 
not appropriate to multiply them by three. Also, a few commenters 
suggested multiplying the MDL by three would not reflect the actual 
lower emissions achieved by any source and as such is unlawful under 
CAA section 112(d).
    Response: We agree with many of the comments related to treatment 
of data reported as detection limit values in the development of MACT 
floors and emissions limits. As we noted at proposal, the statistical 
probability procedures applied in calculating the floor or an emissions 
limit inherently and reasonably account for emissions data variability 
including measurement imprecision when the database represents multiple 
tests from multiple emissions units for which all of the data are 
measured significantly above the method detection level. That is less 
true when the database includes emissions occurring below method 
detection capabilities regardless of how those data are reported.
    The EPA's guidance to respondents for reporting pollutant emissions 
used to support the data collection specified the criteria for 
determining test-specific method detection levels. Those criteria 
ensure that there is only about a 1 percent probability of an error in 
deciding that the pollutant measured at the method detection level is 
present when in fact it was absent. (Reference: ReMAP: PHASE 1, 
Precision of Manual Stack Emission Measurements; American Society of 
Mechanical Engineers, Research Committee on Industrial and Municipal 
Waste, February 2001.) Such a probability is also called a false 
positive or the alpha, Type I, error. This means specifically that for 
a normally distributed set of measurement data, 99 out of 100 single 
measurements will fall within 2.54 x standard deviation of 
the true concentration. The anticipated range for the average of 
repeated measurements comes progressively closer to the true 
concentration. More precisely, the anticipated range varies inversely 
with the square root of the number of measurements. Thus, for a known 
standard deviation (SD) of anticipated single measurements, the 
anticipated range for 99 out of 100 future triplicate measurements will 
fall within 2.54 SD/[radic]3 of the true concentration. 
This relationship translates to an expected measurement imprecision for 
an emissions value occurring at or near the method detection level of 
about 40 to 50 percent.
    By assuming a similar distribution of measurements across a range 
of values and increasing the mean value to a representative higher 
value (e.g., 3 times minimum detection level or 3xMDL), we can estimate 
measurement imprecision at other levels. For an assumed 3xMDL, the 
estimated measurement imprecision for a three test run average value 
would be on the order 10 to 20 percent. This is about the same 
measurement imprecision as found for Methods 23 and 29 indicated in the 
ASME ReMAP study for the sample volumes prescribed in the final rule 
(e.g., 4 to 6 dscm) for multiple tests.
    Analytical laboratories often report a value above the method 
detection limit that represents the laboratory's perceived confidence 
in the quality of the value. This independently adjusted value is 
expressed differently by various laboratories and is called LOQ, PQL, 
or RL. In many cases, the LOQ, PQL, or RL is simply a multiplication of 
the method detection limit. Commonly used multipliers range from 3 to 
10. Because these values reflect individual laboratories' perceived 
confidence, and, therefore, could be viewed as arbitrary, we decline to 
adopt the LOQ, PQL, or RL because such approaches in our view would 
inappropriately inflate the MACT floor standards. Our alternative to 
those inconsistent approaches is discussed below.
    Consistent with findings expressed in reports of emissions 
measurement imprecision and the practices of analytical laboratories, 
we believe that using a measurement value of 3 times a representative 
method detection limit established in a manner that assures 99 percent 
confidence of a measurement above zero will produce a representative 
method reporting limit suitable for establishing regulatory floor 
values.
    On the other hand, we also agree with commenters that an emissions 
limit set from a small subset of data or data from a single source may 
be significantly different than the actual method detection levels 
achieved by the best performing units in practice. This fact, combined 
with the low levels of emissions measured from many of the best 
performing units, led the EPA since proposal to review and revise the 
procedure intended to account for the contribution of measurement 
imprecision to data variability in establishing effective emissions 
limits. In response to the comments about the

[[Page 9390]]

quality of measurements at very low emissions limits especially for new 
sources, we revised the procedure for identifying a representative 
method detection level (RDL).
    The revised procedure for determining an RDL starts with 
identifying all of the available reported pollutant-specific method 
detection levels for the best performing units regardless of any 
subcategory (e.g., existing or new, fuel type, etc.). From that 
combined pool of data, we calculate the arithmetic mean value. By 
limiting the data set to those tests used to establish the floor or 
emissions limit (i.e., best performers), which in this case is a larger 
data set than normally available for establishing NESHAP, we believe 
that the result is representative of the best performing testing 
companies and laboratories using the most sensitive analytical 
procedures. We believe that the outcome should minimize the effect of a 
test(s) with an inordinately high method detection level (e.g., the 
sample volume was too small, the laboratory technique was 
insufficiently sensitive, or the procedure for determining the minimum 
value for reporting was other than the detection level). We then call 
the resulting mean of the method detection levels the representative 
detection level (RDL) because it is characteristic of accepted source 
emissions measurement performance.
    The second step in the process is to calculate 3xRDL to compare 
with the calculated floor or emissions limit. This step is similar to 
what we have used for other NESHAP including the Portland Cement rule. 
As outlined above, we use the multiplication factor of 3 to reduce the 
imprecision of the analytical method until the imprecision in the field 
sampling reflects the relative method precision as estimated by the 
ASME ReMAP study. That study indicates that such relative imprecision 
remains a constant 10 to 20 percent over the range of the method. For 
assessing the calculated floor results relative to measurement method 
capabilities, if 3xRDL were less than the calculated floor or emissions 
limit (e.g., calculated from the upper predictive limit, UPL), we would 
conclude that measurement variability was adequately addressed with the 
initial floor calculation. The calculated floor or emissions limit 
would need no adjustment. If, on the other hand, the value equal to 
3xRDL were greater than the UPL, we would conclude that the calculated 
floor or emissions limit did not account entirely for measurement 
variability. Where such was the case, we substituted the value equal to 
3xRDL for the calculated floor or emissions limit (UPL) which results 
in a concentration where the method would produce measurement accuracy 
on the order of 10 to 20 percent similar to other EPA test methods and 
the results found in the ASME ReMAP study.
    We determined the RDL for each pollutant using data from tests of 
all the best performers for all of the final regulatory subcategories 
(i.e., pooled test data). We applied the same pollutant-specific RDL 
and emissions limit assessment and adjustment procedures to all 
subcategories for which we established emissions limits. We believe 
that adjusting emissions limits in this manner, which ensures that 
measurement variability is adequately addressed relative to compliance 
determinations, is a better procedure than the one applied at proposal, 
which was based on more limited data. We also believe that currently 
available emissions testing procedures and technologies provide the 
measurement certainty sufficient for sources to demonstrate compliance 
at the levels of the revised emissions limits.
5. Basis for New Source MACT
    Comment: Several commenters stated that the proposed limits set for 
new EGUs do not represent the best performing EGU. The commenters state 
that the EPA has chosen the strictest limit irrespective of the EGU and 
that limits for new EGUs should be achievable. According to the 
commenters, no existing EGU is currently meeting the proposed limits, 
which will result in a moratorium on the construction of new coal-fired 
EGUs. Further, commenters state that another result of the EPA's flawed 
approach is that the proposed standards for new EGUs are so low that 
adequate test methodologies to demonstrate compliance do not exist. 
Without accurate testing methodologies, commenters assert that 
contractors will not guarantee that potential emission control 
technologies will meet the proposed standards. Without accurate test 
methodologies and vendor guarantees, commenters believe that financing 
of new facilities will be virtually impossible to secure which will, in 
turn, effectively preclude the construction of any new coal-based EGUs.
    Commenters also stated that the EPA failed to address cumulative 
effects of using multiple pollution control devices in determining MACT 
levels applicable to PM levels. In proposing total PM as a surrogate, 
commenters believe that the EPA failed to consider or address the 
antagonistic effects that adding multiple pollution control devices can 
have on an EGU's HAP emissions. Commenters indicated that EGUs would 
not be able to comply with the proposed new source HCl limit without 
adding a scrubber or some type of sorbent injection to control HCl 
emissions. Adding these HCl control technologies will increase the 
total PM emissions of these units. According to commenters, because a 
fabric filter-alone configuration (the basis for the new source PM 
limit) would not meet all MACT limits, these units may not be the best-
performing units.
    Response: The EPA disagrees with the commenters' statements that no 
existing unit is currently meeting the new source limits. The EPA 
established the new source limits based on data from existing EGUs and 
there is at least one EGU, based on the data available, that is meeting 
all three final HAP limits and at least eight EGUs that are meeting one 
or more of the new source limits. As a result of comments received on 
the full body of data, the EPA has re-ranked the best performing EGUs 
and reviewed the new source limits based on the re-ranking where 
appropriate. Based on the revised ranking, the best performing source 
for PM has changed and that source now forms the basis for the new 
source filterable PM limit in the final rule. The source is a coal-
fired EGU that includes the entire suite of controls that would likely 
be required on a new coal-fired source constructed prospectively (i.e., 
it is a unit with SCR, dry FGD, and FF). Thus, the commenters' concerns 
are no longer relevant as they relate to PM emissions from coal-fired 
EGUs.
    The EPA also believes that the EGUs serving as the basis for the 
new source Hg and HCl limits in the final rule are representative of 
what a new coal-fired EGU would look like to meet all of the requisite 
regulations applicable to EGUs (e.g., NSPS and the CSAPR) as they also 
include the entire suite of controls that would likely be required on a 
new coal-fired source constructed prospectively. The EPA has also taken 
into account the ability of the various test methods to accurately 
measure emissions at the levels being demonstrated by the EGUs in the 
top performing 12 percent in establishing the final limits, and we have 
determined that there are adequate test methods to measure the 
regulated HAP at the new source levels.
6. Achievability of Limits
    Comment: A number of commenters state that the EPA has chosen the 
strictest limit irrespective of the unit and that limits for new EGUs 
should be achievable. According to the

[[Page 9391]]

commenters, no existing unit is currently meeting the proposed new 
source limits, which will result in a moratorium on the construction of 
new coal-fired units. The commenters state that this regulation goes 
beyond protecting public health and will impact the country's choice of 
fuel for energy production. Other commenters state that another result 
of the EPA's flawed approach is that the proposed standards for new 
units are so low that adequate test methodologies to demonstrate 
compliance do not exist. Without accurate testing methodologies, 
commenters allege that contractors will not guarantee that potential 
emission control technologies will meet the proposed standards. Without 
accurate test methodologies and vendor guarantees, commenters believe 
that financing of new facilities will be virtually impossible to 
secure, and that this in turn will effectively preclude the 
construction of any new coal-based units. Commenters maintain that 
adopting standards effectively banning new coal units amounts to a 
momentous change in national energy policy without discussion or 
analysis and far exceeds the EPA's authority.
    Some commenters add that the proposed new source MACT standards do 
not represent rates that have been achieved in practice and are orders 
of magnitude lower than any of the CAA section 112(g) case-by-case MACT 
limits established for the most advanced units in the U.S. coal fleet 
by multiple state agencies.
    Other commenters stated that the synergistic impact of multiple 
controls has not been taken into account in the proposed rules. 
Commenters argue that circumstances exist with respect to the control 
of acid gases, which will require scrubbers or other SO2 
controls that add particulate to the flue gas stream, and that added 
particulate must be removed by PM control devices along with the 
particulate added to the flue gas for EGUs that need to install ACI for 
Hg control. Because particulate devices provide a fixed percent 
reduction of particulate, commenters assert that it is mathematically 
certain that PM performance will decrease because control of both acid 
gases and Hg would add PM to the flue gas stream which would in turn 
decrease performance of the PM control on the relevant mass metric. As 
a consequence, commenters allege that there is no assurance that 
sources can meet the EPA's ``cherry-picked'' floors for acid gases and 
for Hg by ``optimizing'' these systems to meet the performance of the 
floor units because to do so would impact their ability to meet the 
EPA's similarly ``cherry-picked'' total PM floor standard.
    The commenters state that, for existing sources as with the new 
source standard-setting approach, a pollutant-by-pollutant approach 
does not consider what the top performing 12 percent achieve in 
practice for all pollutants and does not consider the antagonistic 
effects of the concurrent use of various control technologies. For 
example, one commenter states that 47 of the 131 sources used to 
calculate the existing source total PM limit only had PM control but no 
acid gas or Hg controls that could emit additional PM. According to the 
commenter, the CAA is clear that standards must be based on actual 
sources and not the product of a pollutant-by-pollutant determination 
resulting in a set of composite standards that do not necessarily 
reflect the overall performance of any actual source. To address these 
issues, the commenter recommends that the EPA use an approach that more 
accurately reflects what actual best performing sources achieve.
    Response: The EPA disagrees with the commenters' contention that 
the pollutant-by-pollutant approach to establishing MACT floors is 
inconsistent with the CAA for the reasons set forth in the response to 
comments on the EPA's MACT floor setting process. In addition, the EPA 
established the proposed new source limits based on data from existing 
EGUs, and there are EGUs that are able to meet the new source limits. 
To the extent the commenters are concerned that no existing source is 
simultaneously meeting all of the new sources limits, we note that the 
EPA has revised the new source standards based on comments and data 
corrections that industry made to data it incorrectly provided in 
response to the utility ICR. We have identified at least one source 
that is meeting all of the new source MACT limits in the final rule.
    We disagree with commenters that suggest the proposed new source 
standards are invalid because they are more stringent than CAA section 
112(g) case-by-case MACT limits established by state agencies. As 
commenters note, states, not the EPA, established the CAA section 
112(g) standards, and they did so based on the information available to 
them. The EPA likewise must establish CAA section 112(d) standards 
based on the available data. We have considered the available data and 
information, including the 2010 ICR data, and complied with the 
requirements of CAA section 112(d) in establishing the standards in 
this final rule. That the final standards are more stringent than CAA 
section 112(g) standards issued by certain state agencies has no 
bearing on the legitimacy of the standards at issue here.
    The EPA agrees with commenters that the SO2 and some Hg 
controls may add to the PM loading and that it is reasonable to 
establish the new source standard based on an EGU that has a suite of 
controls that will be required of any new source. For example, new 
coal-fired EGUs will be required to comply with the utility NSPS and 
may have to comply with the CSAPR and other requirements (e.g., SIP or 
state-only requirements). Commenters are also correct that the proposed 
new source PM surrogate standard was based on a source that is not like 
a coal-fired EGU that would be constructed today (i.e., an EGU with 
only PM control and no SO2 controls).
    The final standard is not based on the source used to establish the 
proposed limit. As stated above, industry commenters provided data 
corrections and new data and the EPA considered that new and revised 
data in establishing the final standards. We re-ranked all the coal-
fired EGUs based on the new data. The new ranking of coal-fired EGUs 
resulted in a change of the source we used to establish the new source 
PM surrogate standard for non-mercury metal HAP. The basis for the new 
source limit in the final rule is a unit that has a full suite of 
controls similar to what would be required for any new coal-fired EGUs 
(i.e., it is a unit with SCR, dry FGD, and FF). The EPA has identified 
at least one EGU meeting all of the final new source limits; thus, the 
EPA does not believe that it is finalizing standards that ``ban'' new 
coal-fired generation as indicated by the commenter.
    The EPA also disagrees that the final new source standards are so 
stringent that there are not adequate test methods available to 
determine compliance with the standards. The EPA has taken into account 
the ability of the various test methods to accurately measure emissions 
at the levels being demonstrated by the best performing EGUs in 
establishing the final limits. This has been done through use of the 
3XRDL (discussed elsewhere in this preamble and the Response to 
Comments document) and through adjustments to the sampling time 
requirements for certain of the HAP.
7. Comments on Technical Approaches
    Comment: Commenters disagreed with the EPA's use of data from 
multiple units exhausting through a common stack and argued that the 
EPA unreasonably treated data from multiple

[[Page 9392]]

units exhausting through a single stack as multiple data points in 
establishing the MACT floors. The commenters believe it is improper to 
count a single data point from a multiple-unit common stack as multiple 
data points. The commenters state that where two units exhaust through 
a common stack, the performance is not that of two sources, but only 
one. The commenters indicate that emissions performance that is 
actually achieved reflects combined operation, which cannot rationally 
be split into two parts (data points) because this emissions 
performance was not achieved by two separate sources. Commenters assert 
that although it may be acceptable for the EPA to surmise that the 
combined performance of multiple EGUs and pollution control devices 
represents an emissions control strategy that could be a best 
performer, thereby entitling the Agency to use the data at all, the 
fact is there is only one performer not two. Commenters contend that 
apart from being inconsistent with applicable MACT case law, counting 
combined stack emissions as two or more data points is unreasonable 
because it dampens variability and over-represents the emissions data 
by creating multiple ``performers'' or sources when there is in fact 
only one. Commenters note that in the major-source Industrial Boiler 
NESHAP, the EPA argued its approach of creating two data points from a 
single combined stack data point is reasonable because it cannot 
separate the comingled fraction of the emissions from the different 
emission points. Commenters state that this is irrelevant, believing 
that there is no basis to separate these emissions because the MACT 
floor is based on best performing sources and there is only a single 
source.
    According to commenters, the EPA cannot determine what amount of 
the overall performance of a combined stack data point is the specific 
result of the combination. Commenters assert that the EPA also argues 
that applying the emissions equally to multiple units exhausting 
through a single stack ``accurately represents the emissions of those 
units on average.'' Commenters believe that is simply not correct and 
there is no plausible factual basis for that statement, believing that 
there is no unit that ``achieved'' those emissions. Rather, the data 
represent the combined weighted average of two units, without knowing 
how either unit actually performed. One commenter also stated that in 
several instances when a facility operated tandem or multiple EGUs but 
only submitted a single stack measurement, the EPA used the single 
stack measurement to represent Hg emissions from the facility's other 
stacks.
    Response: The EPA disagrees with commenters. As in the major-source 
Industrial Boiler NESHAP, the EPA continues to believe that the 
emissions from the common stack represent the average emissions of the 
EGUs exhausting to the common stack and are representative of both 
EGUs. Commenters have provided no data to support the contention that 
this assumption is false. In addition, commenters' contention that 
distinct EGUs (i.e., boilers) are one source if they emit out of a 
common stack is not consistent with the CAA section 112(a)(8) 
definition, which clearly applies to the individual boiler units with a 
capacity of more than 25 MW. It would not be reasonable in light of 
that definition to consider the emissions from two boilers to a common 
stack as the emissions of one EGU. The EPA only used data from combined 
stacks where both EGUs were operating or where the owner/operator 
certified that no air leakage could occur. The EPA expects that 
companies will comply with the final rule by conducting testing at the 
common stack as that is usually where the sampling locations are 
(rather than in the intermediate ductwork) and will report the results 
as being for each EGU.
    The EPA has reviewed the data based on comments received and does 
not believe that there are any inconsistencies in the data set used for 
the final rule. In the MACT floor analysis, the EPA only used data from 
stacks that were tested or for which test data were provided. These 
stack measurements were not used to represent emissions from other, 
non-tested, stacks in the MACT analysis.
8. Alternative Units for Emission Limits
    Comment: Several commenters submitted a variety of alternatives to 
the input- or output-based MACT floor limits as means of establishing 
the MACT floors. Some commenters suggested emission reductions or 
removal efficiencies. These commenters suggest that a percent reduction 
MACT metric be considered as an alternative, and not a substitute, to 
some of the proposed MACT numerical limits, particularly those that 
appear too problematic to meet in reality. A necessary data format and 
protocol could be developed for some HAP, such as Hg, that would allow 
an appropriate percent reduction alternative to be developed. 
Commenters believe that the Brick MACT decision stands for the 
proposition that a MACT level cannot be based on a specific technology; 
commenters are advocating that a percent reduction format would specify 
the level or reduction but would not dictate any specific control or 
methodology.
    Comments were also received that some state programs contain Hg 
emission limits that are more stringent than the EPA's proposed 
emission limits. The programs of Connecticut, Massachusetts, New 
Hampshire, New Jersey, and New York were noted. Commenters provided 
information on these states' Hg emission limits, which often are in the 
form of either a lb/TBtu format or a percent reduction. Commenters 
noted that EGUs in these states were in compliance with the state 
regulations and, therefore, the EPA's emission limits should be more 
stringent.
    Response: The EPA disagrees with the commenters' suggestion that a 
percent reduction standard should be included in the final rule. The 
EPA notes that the inability to account for Hg removed from the coal 
prior to combustion was not the only reason provided for not using a 
percent reduction format. As noted in the proposal preamble (76 FR 
25040), we did consider using a percent reduction format for Hg. We 
determined not to propose a percent reduction standard for several 
reasons. 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 because we did not have the data to account for those practices. 
Specifically, 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). Such 
an approach would be difficult to implement and enforce. Moreover, we 
do not have the data necessary to establish percent reduction standards 
for HAP at this time. Depending on what was considered to be the 
``inlet'' and the degree to which precombustion removal of HAP was 
desired to be included in the calculation, the EPA would need (e.g.) 
the HAP content of the coal as it left the mine face, as it entered the 
coal preparation facility, as it left the coal preparation facility, as 
it entered the EGU, as it entered the control devices, and as it left 
the stack to be able to establish percent reduction standards. We do 
not have this type of information.
    The EPA believes that an emission rate format allows for, and 
promotes, the use of pre-combustion HAP removal processes because such 
practices will

[[Page 9393]]

help sources assure they will comply with the proposed standard. A 
percent reduction requirement would likely limit the flexibility of the 
regulated community by requiring the use of a control device. In 
addition, as discussed in the Portland Cement NESHAP (75 FR 55002; 
September 9, 2010), the EPA believes that a percent reduction format 
negates the contribution of HAP inputs to EGU performance and, thus, 
may be inconsistent with the D.C. Circuit's rulings as restated in the 
Brick case (479 F.3d at 880) which say, in effect, that it is the 
emissions achieved in practice (i.e., emissions to the atmosphere) that 
matter, not how one achieves those emissions.
    The 2010 ICR data confirm that plant inputs likely play a role in 
emissions to the atmosphere. These data indicate that some EGUs are 
achieving lower Hg emissions to the atmosphere at a lower Hg percent 
reduction (e.g., 75 to 85 percent) than are other EGUs with higher 
percent reductions (e.g., 90 percent or greater). However, we are not 
sure whether these data accurately reflect the total percent reduction 
mine-to-stack because we do not have all the data necessary to make 
that determination. Thus, we proposed to establish numerical emission 
standards for Hg HAP emissions from EGUs and we are finalizing 
numerical emission standards. The same issues prevent us from 
considering percent reduction standards for the other HAP emitted from 
EGUs.
    With regard to the comments relating to some state programs being 
more stringent than the EPA's proposed limits, the EPA would note that 
many of the programs identified by one commenter have an ``either/or'' 
format for their Hg standards. That is, an EGU can either meet an 
emission limit (e.g., lb/TBtu) or achieve a percent reduction. The 
commenter did not note which form of the standard the EGUs were meeting 
so it is unclear whether the standards are in fact more stringent. In 
any case, CAA section 112(d) does not mandate that federal standards be 
more stringent than state requirements for HAP emissions. Furthermore, 
states are authorized to establish standards more stringent than this 
final NESHAP so promulgation of this rule will in no way affect a 
source's responsibility to comply with an otherwise applicable state Hg 
or other HAP standard.
9. Beyond-the-Floor
    Comment: Several commenters stated that the proposed beyond-the-
floor Hg limit for low rank coal EGUs is based on too little data and 
is technically and economically unattainable, noting that the EPA's 
proposed beyond-the-floor limit is based on only three samples from a 
single test held at only one EGU, which is not enough data to develop 
such a limit, especially as more data were available for this EGU in 
the database. Commenters noted that although this one EGU may have been 
able to achieve the proposed limit during this one test, the three 
samples are not adequate to demonstrate the long-term ability of this 
EGU to meet that limit consistently, let alone the long-term abilities 
of the top 12 percent of all low rank coal EGUs to meet that limit 
consistently. Given Texas lignite's particularly high rates of 
variability of Hg concentration, and the inability to minimize this 
variability, the commenters believe that the EPA is obliged to have 
more, not less, data to support the proposed beyond-the-floor Hg limit 
for low rank coal EGUs. One commenter added that the EPA's decision to 
require a beyond-the-floor limit for the low rank virgin coal 
subcategory does not comply with CAA section 112(d)(2). Some commenters 
also contended that the EPA failed to include the cost of a baghouse in 
its beyond-the-floor analysis. They note that, according to the EPA, in 
order to comply with the proposed EGU MACT rule, units will either fuel 
switch to a lower Hg fuel or retrofit air pollution controls.
    Response: The EPA notes that all of the low rank virgin coal-fired 
EGUs for which data were submitted in response to the 2010 ICR were 
meeting the Hg floor limit (11 lb/TBtu). Four of the EGUs have ACI 
systems installed and three of the four EGUs tested were also meeting 
the beyond-the-floor Hg emission limit of 4.0 lb/TBtu. Those three 
units were achieving control levels of greater than 95 percent (fuel to 
stack). The other low rank virgin coal-fired EGUs that are not 
currently meeting the beyond-the-floor emission limit do not have 
installed Hg-specific controls. An analysis of the Hg content of the 
fuel used during the 2010 ICR testing suggests that control in the 
range of 80 to 90 percent (fuel to stack) would be needed to meet the 
beyond-the-floor limit of 4.0 lb/TBtu. One low rank virgin coal-fired 
EGU achieved 75 percent control with no Hg-specific control technology 
(e.g., ACI).
    The EPA believes that its beyond-the-floor analysis is appropriate, 
including the costs analyzed. The EPA's cost analysis is meant to serve 
as an average for all sources in the subcategory recognizing that some 
EGU's costs will be more and some less; EGUs whose costs are higher are 
not exempted from the regulation. Further, five EGUs in the subcategory 
are meeting the final beyond-the-floor limit based on available data 
(see the MACT Floor analyses in the docket), and, in any case, CAA 
section 112(d) does not require that a specified percentage of sources 
in a category or subcategory be able to meet the MACT standard that is 
established. This is even truer for beyond-the-floor standards which 
are set at levels beyond what the average of the best performing 
sources are achieving in practice and instead based on what is 
achievable. Commenters have failed to provide any data that supports 
the contention that some EGUs in the subcategory will not be able to 
achieve the standards with additional controls.
    Comment: Commenters indicated that the EPA has not justified a 
beyond-the-floor limit for Hg for new IGCC units. The EPA's choice of 
the beyond-the-floor Hg limit for new IGCCs is not derived from IGCC 
test data from the 2010 ICR and commenters allege that the EPA has not 
provided adequate justification for its decision from a technology 
capability assessment. Commenters note that ACI for Hg treatment of 
coal-derived syngas is not in use in any operating IGCC plant today, 
nor can it be used in the same fashion as it is used at conventional 
coal-fired EGUs. Commenters assert that the EPA also lacks data with 
respect to new IGCC units, yet the EPA proposed beyond-the-floor MACT 
limits for new IGCC sources. The commenters assert that the EPA's 
limits for new IGCC sources are based on beliefs, predictions, 
projections and design target assumptions. The limits from the 2007 DOE 
Report referenced in the preamble are based on environmental target 
assumptions. These IGCC environmental targets were chosen to match 
Electric Power Research Institute (EPRI) design basis from their Coal 
Fleet for Tomorrow Initiative. Commenter states that EPRI notes that 
these were design targets and were not to be used for permitting 
values. Commenters assert that the EPA has simply not justified its 
process for going beyond-the-floor for new IGCC units and that, without 
sufficient justification, the EPA actions are unsupported.
    Two commenters provided permit information, based on IGCC units 
currently under construction, for PM and Hg emissions. One commenter 
requested that the proposed new MACT floor limit for PM be modified to 
address the two scenarios for duct burners at IGCC plants, syngas-fired 
and natural-gas-fired. The commenter requested the 0.050 lb/MWh limit 
be increased to at least 0.068 lb/MWh

[[Page 9394]]

based on gross energy output from the combined cycle generating unit 
when operated with duct burners fired with syngas. The 0.068 lb/MWh 
value is consistent with the calculated emission ceiling for its permit 
to construct for this operating scenario. According to the commenter, 
there is not sufficient experience with syngas turbines for 
manufacturers to guarantee performance in the 0.050 lb/MWh range. The 
0.0681b/MWh performance basis proposed by the commenter was calculated 
based on the emission guarantees that the commenter was able to obtain 
for a turbine fired on the syngas. The commenter also requested that 
the 0.050 lb/MWh limit be increased to 0.083 lb/MWh based on gross 
energy output from the combined cycle unit when operated with duct 
burners fired by natural gas. The commenter indicated that, depending 
on market conditions, the syngas produced at an IGCC may have more 
value as a raw material for producing co-products than it would have as 
duct burner fuel. Where that is the case, the economic viability of an 
IGCC would be enhanced by firing the duct burners on natural gas and 
diverting that syngas to manufacture of a co-product. The commenter's 
air permits are currently based on the use of syngas as duct burner 
fuel; however, the commenter is currently examining an alternative 
operating scenario that may result in amendments to the air permits to 
authorize firing natural gas in the duct burners. Commenter states that 
preliminary calculations indicate that the PM limit would need to be 
set at 0.083 lb/MWh gross energy output when operated with duct burners 
fired with natural gas.
    The commenter also noted that there is not sufficient test data to 
precisely predict the Hg emissions performance of even the best-
controlled IGCC units, other than that IGCC Hg emissions are expected 
to be much less than those for EGUs that directly burn coal. In its 
permit application, the commenter proposed to establish a new standard 
for Hg removal in IGCC units by treating the syngas in catalytic 
reactors. The catalytic reactor system is expected to achieve greater 
than 95 percent Hg removal using either sulfur-impregnated activated 
carbon or alumina catalyst. In the absence of actual stack test data, 
the commenter has had to estimate expected emissions based on 
engineering estimates of how much Hg may arrive in the syngas routed to 
the catalytic reactors. Based on these engineering estimates and 95 
percent Hg removal in the catalytic reactors, the commenter believes 
that the resulting Hg emission limit for a state-or-the-art IGCC unit 
would be 0.003 lb/GWh, which is much less than the Hg emissions for 
EGUs that directly burn coal.
    The commenter notes that IGCC units are still in their infancy. 
Funding for them will be very difficult or unavailable if there is a 
regulatory limit below the level that can be supported by vendor 
guarantees. Given the important role that IGCC units may have in 
meeting global energy and climate stability goals, the commenter 
believes it would be a mistake to erect barriers to the implementation 
of this technology. The commenter stated that the EPA can reevaluate 
the appropriate levels for future IGCC units after demonstration units 
which incorporate effective controls have been built and tested.
    Response: The EPA is not finalizing the proposed new source 
standards for IGCC units. As commenters noted, EPA proposed beyond-the-
floor limits for IGCC units based on the performance of PC-fired EGUs 
and solicited data from IGCC units that would represent what a new IGCC 
could achieve. We received information that there are new IGCC units 
permitted and under construction. The EPA believes one IGCC unit under 
construction for which permit data were provided is representative of 
both current technologies and of IGCC units that will be built in the 
near-term future. Therefore, the EPA believes these permit levels 
should be the basis of the new source IGCC emission limits and the 
Agency is finalizing the PM and Hg limits on that basis, as that source 
will be required to comply with its permitted limits once constructed 
and it is a similar source. However, permit limits were only provided 
for PM and Hg; therefore, the EPA is finalizing the new source limits 
for acid gas HAP based on data from the best-performing of the existing 
IGCC units for the respective HAP.

B. Rationale for Subcategories

    Many commenters stated that the EPA should have proposed more 
subcategories, while others believed that too many subcategories were 
proposed. Many different issues were raised by commenters, and some of 
the key issues that were considered in the final rule (some of which 
led to changes in the final rule) include: the technical deficiencies 
in the definition for the low-Btu coal subcategory; additional 
subcategorization of the coal-fired EGU population; the need for 
subcategorization of distillate vs. residual oil-fired EGUS; the need 
for a limited-use subcategory for EGUs that operate for only a small 
percentage of hours during a year; and the need for a non-continental 
liquid oil subcategory for island units that have limited fuel options 
and other unique circumstances. The comments and the EPA responses are 
provided below.
    In general, the EPA has reviewed the data provided and continues to 
believe that the coal-fired EGU subcategories proposed are the only 
ones supported by the data, though we have revised the basis for EGUs 
designed to burn low rank virgin coal as discussed above. The EPA may 
not subcategorize by air pollution control technology type as requested 
by a few commenters. Further, the EPA has reviewed the other suggested 
coal-fired subcategories and finds no basis for further 
subcategorization (e.g., based on boiler design, boiler size, or duty 
cycle).
1. Coal Subcategories
    Comment: Commenters noted that although other subcategories had 
been evaluated, including subcategorization of other coal ranks, no 
other coal rank subcategorization was proposed. Commenters submit there 
should be subcategories for the coal ranks of bituminous, 
subbituminous, and lignite. The commenters noted that such treatment 
would be consistent with past practice (e.g., CAMR where the 
differences in the type of emissions of Hg due to the different 
chemical properties of coal within differing fuel ranks was discussed). 
Commenters note that activated carbon has been shown to be very 
effective when used in combination with low chlorine coals (such as 
western subbituminous coals); however, activated carbons can suffer 
from poor performance when used with high sulfur coals. Commenters 
indicate that firing high sulfur coals (especially when an SCR is also 
used) can result in sulfur trioxide (SO3) vapor in the flue 
gas stream. The SO3 competes with Hg for binding sites on 
the surface of the activated carbon (or unburned carbon) and limits the 
effectiveness of the injected activated carbon. But another commenter 
noted that an SO3 mitigation technology, such as dry sorbent 
injection (DSI, e.g., trona or hydrated lime), applied upstream of the 
ACI can minimize this effect.
    Commenters also stated that without further subcategorization the 
economic impacts on individual Midwestern states will be particularly 
acute as huge segments of the U.S. coal reserve will be disenfranchised 
by this rule. According to the commenters, the EPA did not even attempt 
to legitimately analyze this issue and, thus, in their opinion the 
Agency's proffered rationale for

[[Page 9395]]

declining to further subcategorize based on the acid gas standard is 
belied by the record. The commenters believe that the EPA needs to 
better align this rule with its previous position in CAMR and further 
subcategorize based on coal type.
    Other commenters are opposed to any further subcategorization based 
on coal rank. Because many sources blend several ranks of coal on a 
regular basis, commenters believe that establishing coal rank 
subcategories would create numerous opportunities for sources to game 
the regulations and substantially increase emissions. Commenters stated 
that there is no need for such an approach since modern pollution 
controls can accommodate a wide range of coals. These commenters 
believe that EGUs firing different ranks of coal are not fundamentally 
different in size, class, or type in a way that impacts emissions or 
that limits the availability of controls. The commenters believe that 
emissions of fuel-dependent HAP can be controlled by either changing 
the fuel prior to combustion or by removing the HAP from the flue gas 
after combustion. Commenters state that ACI systems, DSI controls, and 
PM controls are available for installation at units firing sub-
bituminous coal and are equally available for units firing bituminous, 
anthracite, or lignite coal. These commenters also believe that as long 
as a control option is commercially available, the cost for a 
particular EGU is irrelevant to the EPA's development of emission 
standards based on MACT. Commenters stated that subcategories based on 
coal rank would make a meaningful consideration of fuel switching 
impossible, contrary to the judicial mandate to consider substitution 
of materials in setting the floor and the statutory mandate to consider 
substitution of materials in the beyond-the-floor analysis.
    One commenter stated that although they previously supported the 
subcategorization of coal-fired units on the basis of coal rank, they 
no longer object to grouping units that burn bituminous and 
subbituminous coals in a single category because the prior basis for 
subcategorization no longer exists. The commenter indicated that at the 
time of CAMR, it was widely recognized that although coal-fired units 
combusting bituminous coal, with its higher concentration of chlorine 
and, therefore, ionic Hg, could effectively limit Hg emissions by 
utilizing existing control technologies such as scrubbers, units 
burning subbituminous coal could not do so with the same controls 
because of the coal's higher levels of elemental Hg. The commenter 
stated that activated carbon was only a fledgling and unproven 
technology at the time; today, however, activated carbon has been 
proven, and units burning bituminous and subbituminous coal can achieve 
the same levels of emissions for Hg and other HAP. Consequently, the 
commenter believes the prior basis for subcategorization no longer 
exists and the commenter, therefore, agrees that coal-fired EGUs 
burning bituminous and subbituminous coals ought to be grouped in a 
single category.
    Response: The EPA disagrees with commenters that additional coal-
fired subcategories are warranted and has not provided any in the final 
rule. Commenters are correct that additional subcategorization was 
proposed in January 2004. Whether or not such subcategorization was 
warranted at that time, the EPA believes that the current conditions 
are such that, even if appropriate at that time, such further 
subcategorization is not appropriate at this time.
    When all of the factors noted by commenters have been reviewed, 
with the exception of Hg for certain units, as discussed above, the EPA 
does not believe that the HAP emissions to the atmosphere are 
sufficiently different from coal-fired EGUs to warrant further 
subcategorization. There are EGUs firing bituminous, subbituminous, and 
coal refuse among the top performing units for Hg and EGUs firing 
bituminous, subbituminous, lignite, and coal refuse are all among the 
top performers for the acid gas HAP and non-mercury metallic HAP 
indicating that the MACT floor limits established based on these units 
are achievable by units burning all ranks of coal.
    As noted by commenters, ACI, not fully developed in 2004, is now 
able to effect Hg control levels on subbituminous coals such that 
similar emissions to the atmosphere may be achieved as those achieved 
by higher-chlorine bituminous coals when FGD systems are used or by 
coal refuse EGU with less controls. Thus, in looking at the total 
system, similar emissions to the atmosphere are achieved by all of 
these coal ranks. The EPA has addressed elsewhere in this document its 
rationale for not subcategorizing by coal chlorine content. The EPA 
does not believe that any fundamental discrimination between coal ranks 
will occur as a result of the final rule, though clearly some sources 
will be required to install greater controls to comply with the final 
standard. We maintain that such result is consistent with the intent of 
CAA section 112 standards, which are not intended to have an outcome 
whereby all sources can comply with final standards without any action.
    The EPA agrees, in theory, that EGUs are designed around a basic 
set of coal characteristics. However, the 1999 ICR demonstrated that 
numerous EGUs have conducted trial burns and gained sufficient 
experience such that co-firing blends of various coal ranks is now 
common practice. In fact, the EPA believes that such blends may be 
modified daily, depending on the characteristics of the coal being 
burned and on the level of generation needed. The extent of blending, 
and the ability to switch the blends on short notice, does not lend 
itself (or, in fact, argue for) additional subcategorization.
    The EPA disagrees with any assertion that the EPA ignored possible 
subcategorization approaches or that it has insufficient data upon 
which to base or evaluate various subcategories. The EPA fully examined 
the record, which demonstrates that coal-fired EGUs, with the exception 
of certain units for Hg, have similar HAP emissions profiles and that 
similar control approaches are available to such EGUs. Although 
commenters suggested additional subcategories were warranted, they 
failed to provide sufficient data to support their proposed alternative 
subcategories. As noted elsewhere, the EPA does not disagree with 
commenters that there are some differences in EGUs. However, the EPA 
does disagree with commenters that those differences result in 
differences in emissions to the atmosphere such that additional 
subcategorization is justified.
    Failing to demonstrate that coal-fired EGUs are different based on 
emissions, the commenters turn to economic arguments, asserting that 
failing to subcategorize will impose an economic hardship on certain 
sources. Congress precluded consideration of costs in setting MACT 
floors, and it is not appropriate to premise subcategorization on costs 
either. See S. Rep No. 101-228 at 166-67 (5 Legislative History at 
8506-07) (rejecting the implication that separate categories could be 
based on ``assertions of extraordinary economic effects''); see also 
NRDC v. EPA 489 F.3d 1364 (D.C. Cir. 2007) (holding that EPA properly 
declined to create a subcategory for a particular source and rejecting 
the argument that the source may have to incur more costs to comply 
with the rule without such subcategory).
    The final limits are based on EGUs currently operating with 
available controls. As noted above, the record shows that the various 
types of EGUs are represented in the floors, with the exception of 
certain units for Hg, which

[[Page 9396]]

indicates that the levels are achievable by such units. Thus, the data 
actually show that the MACT standards are achievable for a wide variety 
of EGUs.
    In addition, the EPA believes it has fulfilled the CAA section 
112(c)(l) directive that ``[t]o the extent practicable, the categories 
and subcategories listed under this subsection shall be consistent * * 
*'' with those of CAA section 111, notwithstanding commenters assertion 
to the contrary. The decision on whether to directly align CAA sections 
112 and 111 subcategories is discretionary and EPA has reasonably 
exercised its discretion in declining to create additional 
subcategories for coal-fired EGUs based on the record, with the 
exception of certain sources for Hg.
    Finally, the EPA disagrees with the commenters that suggest that 
EPA lacks the legal authority to consider material inputs when 
considering subcategories. We agree, however, that material inputs must 
be considered when establishing MACT standards for the subcategories 
that are established. We also believe a meaningful consideration of 
fuel switching can occur even if sources are subcategorized based on 
fuel inputs because EPA considers fuels switching in evaluating 
potential beyond-the-floor alternatives.
    Comment: One commenter stated that the EPA should establish an 
existing source acid-gas subcategory for high sulfur or high chlorine 
coals because the same factors that the EPA relied on to support a low 
rank virgin coal subcategory for Hg are also present in the high sulfur 
or high chlorine coal context. The commenter stated that the data 
indicate that even well-controlled units burning high sulfur coals 
would not be in the top performers for acid gases even at removal rates 
of 95 or 96 percent. The commenter added that absent such a 
subcategory, about 12 percent of coal deliveries (2005 data), and the 
vast majority of coal shipped from the states of Indiana, Ohio, and 
Illinois (2008 data), would become unusable. The commenter expressed 
support for the alternative SO2 standard for units unable to 
meet the HCl standard; however, the commenter also believed that it is 
appropriate to establish a coal chlorine or sulfur content-based 
subcategory for the alternative SO2 standard. The commenter 
stated that coal testing data indicate a clear break in chlorine 
concentrations in the coals burned by EGUs, as well as in sulfur 
content. The commenter indicated that there are factors supporting a 
high sulfur or high chlorine coal subcategory that are similar to those 
that the EPA relied upon to support a Hg subcategory for low rank 
virgin coal. According to the commenter, the EPA's key rationale for a 
Hg subcategory for low rank virgin coal was that no low rank virgin 
coal-fired unit appeared in the ``top performing 12 percent of sources, 
indicating a difference in the emissions for this HAP from these types 
of units.'' The EPA did not establish other subcategories because ``the 
data did not show any difference in the level of HAP emissions and, 
therefore, we have determined that it is not reasonable to establish 
separate emissions limits for other HAP.'' The commenter indicated that 
the EPA does not need emissions data to know that even well-controlled 
units burning higher sulfur coals would be unable to meet the 
alternative SO2 emissions rate, and would therefore also not 
appear in the top 12 percent of performing units.
    Response: The EPA disagrees with commenters that subcategories 
should be established for high sulfur and high chlorine coals. It 
appears from the comments that it is not in fact the chlorine content 
that is at issue but the sulfur content of the coal. Commenters state 
that they are unable to meet the HCl limit, but they only provide 
information indicating it would be difficult to meet the alternative 
equivalent SO2 limit. In fact, our data show that coals with 
chloride contents as high as 2,100 ppm (0.16 lb/MMBtu) were burned by 
EGUs making up the MACT floor pool of sources for the final HCl 
emission limit and that the best-performing unit was burning coal with 
a maximum chloride content of 1,200 ppm. The median chloride level for 
bituminous coals identified from data submitted through the 1999 ICR 
was 1,030 ppm so we believe that the coals represented in the MACT 
floor pool indicate that the final limits are achievable with high-
chlorine coals. We have determined that HCl removal is very effective 
using a number of different types of FGD systems. Absent information 
demonstrating that sources are unable to meet the proposed HCl limit 
due to the chlorine content of the coal, we believe it is unnecessary 
and inappropriate to consider subcategorizing based on chlorine content 
in the coal.
    In addition, as noted above, the SO2 limit is an 
alternative equivalent standard that is available to sources that have 
an SO2 control and CEMS and operate the controls at all 
times. The EPA did not provide the alternative equivalent standard for 
sources that could not meet the HCl limit as one commenter suggests; 
instead, we provided the standard as a convenience and cost saving 
measure to EGUs with installed FGD systems because we recognize that 
many EGUs have SO2 CEMS. Sources are required to comply with 
the HCl limit as a surrogate for all the acid gas HAP or the 
SO2 limit as an alternate equivalent standard. Commenters 
have not demonstrated that they are unable to meet the HCl standard and 
our data show that the standard is achievable even for high chlorine 
coals.
    Comment: Several commenters supported the development of a separate 
subcategory for fluidized bed combustors (FBC) or circulating fluidized 
bed (CFB) EGUs. The commenters encouraged the Agency to consider 
subcategorization of FBC EGUs for Hg emissions noting that the industry 
has long contended that the design, construction, and operation of FBCs 
are different than conventional boilers and that FBCs employ 
fundamentally different processes than conventional PC-fired EGUs. The 
selection of an FBC unit over a conventional PC boiler is driven in 
large part by fuel characteristics. The commenters assert that, as a 
result, the emissions profile of FBC units generally differ from 
conventional PC boilers because FBC units more advantageously combust 
waste coals, as well as coal blends with other carbonaceous material. 
The commenters stated that the EPA did not discuss the design 
differences between FBC units and PC units in the preamble to this 
proposed rule unlike what the Agency did when it previously proposed Hg 
MACT limits in January 2004. Commenters state that, for these reasons, 
FBC units can be considered a distinct type of boiler.
    The commenters noted that an examination of the 40 ``best 
performing'' units for Hg emissions in the proposed MACT floor 
spreadsheet showed that 14 of those units are FBC units. The commenters 
maintained that had FBC units performed as well as conventional PC 
boilers, 2 units would have been expected to be in the top 40. The 
commenters allege that the far higher percentage of FBCs in the top 40 
leads to the conclusion that these units are different from 
conventional PCs with regard to Hg emissions and, as a result, should 
have been placed in their own subcategory. Further, commenters noted 
that the largest FBC has a nameplate capacity of about 300 MW while the 
largest conventional boilers have nameplate capacities of around 1,300 
MW.
    The commenters stated that FBCs combust relatively large coal 
particles in a bed of sorbent or inert material at a lower degree of 
combustion efficiency.

[[Page 9397]]

Fluidized bed units operate at less than half of the temperature of a 
conventional boiler and have much longer fuel residence times. 
Conventional boilers pulverize coal to a very fine particle size to 
maximize combustion efficiency and minimize unburned carbon. As a 
result, the commenters noted that FBCs typically have higher levels of 
unburned carbon present in the ash, which behaves much like activated 
carbon and helps promote more efficient Hg removal. Accordingly, 
commenters maintain that Hg emissions of FBC boilers and PC boilers are 
statistically different, with emissions from FBCs significantly lower 
than those from PC boilers. According to commenters, this statistically 
significant difference in the Hg emissions profiles for these two 
distinct boiler technologies argues in favor of the creation of a 
separate subcategory for FBCs, as there is no control technology that 
PCs could install that would result in emissions reductions similar to 
those achieved by FBCs. The active quantity of calcium oxide (lime-CaO) 
available in a FBC boiler is also orders-of-magnitude greater than 
compared to a PC boiler, whose alkalinity is derived solely from the 
coal's mineral content. Significantly higher CaO can alter the process 
chemistry in the boiler, including the oxidation levels of Hg.
    One commenter stated that the EPA properly declined to 
subcategorize units based on design type where there is no indication 
that any physical distinctions among unit designs have a meaningful and 
substantial impact on HAP emissions. The commenter indicated that it 
would be inappropriate to subcategorize FBCs because there is no 
evidence to support a determination that FBC design is responsible for 
a unit falling in or out of the top 12 percent for a particular HAP.
    Response: The EPA acknowledges that there are design and operation 
differences between conventional PC-fired EGUs and FBC/CFB EGUS; 
however, the commenters are incorrect in asserting that the HAP 
emissions levels and characteristics are sufficiently distinct from 
other coal-fired EGUs to support subcategorization. Further, commenters 
fail to note that FBC EGUs were not subcategorized in CAMR even though, 
as commenters note, such design and operation differences were cited 
there. The fact that FBC units operate at lower temperatures is of no 
consequence as they still operate at temperatures high enough to 
vaporize Hg.
    Commenters assert that FBC units are disproportionately represented 
among the best performers, with the inference being that they were 
selected to test in the 2010 ICR because of their boiler design. 
However, FBC EGUs were not specifically selected as best performers for 
Hg, as EPA did not select any EGUs based on a determination that they 
were best performers for Hg (as noted elsewhere, we had no basis for 
selecting EGUs as being best performers for Hg), and to the extent CFB 
units were selected in the 2010 ICR, they were selected because we 
determined they were best performers for non-mercury metallic HAP, acid 
gas HAP, or organic HAP or because they were randomly selected among 
the non-best performers for those three HAP groupings. Thus, the CFBs 
were selected for testing under the 2010 ICR based not on their boiler 
design but, rather, based on the age and on their PM and FGD control 
systems (as noted in the Supporting Statement for the 2010 ICR). As 
many FBC EGUs, including CFB EGUs, are relatively new, they were 
included in the non-mercury metallic HAP group selected for testing 
(because their PM controls were among the 175 newest), the acid gas HAP 
group selected for testing (because FBC was considered to be an FGD 
system and the units were among the 175 newest), and organic HAP 
testing (because they were among the newest and, thus, determined to be 
among the most efficient).
    The effect on Hg emissions is not what commenters suggest because, 
although, as noted by commenters, FBC units may be found among the 
better performers (among the top 10 EGUs) on the Hg MACT floor 
spreadsheet, they are also found in the range of 221 to 226 EGUs (of 
393 data points). The fact that FBC units have ``vastly dissimilar ash 
properties'' that may contain higher levels of lime or unburned carbon 
in the fly ash than conventional PC EGUs does not indicate that the 
overall system behaves any differently with regard to emissions to the 
atmosphere (the key metric) than a conventional PC EGU with add-on 
controls. The asserted higher levels of unburned carbon result in a 
range of effectiveness of Hg control that is similar to that of ACI 
found on PC EGUs; such ACI control may be found on EGUs that are among 
the better performers as well as on EGUs as low as 369 on the list of 
data points. Thus, the EPA disagrees that FBC units are 
disproportionately represented in the Hg floor and that their inclusion 
is somehow inappropriate or leads to skewing of the analysis.
    All types of coal-fired EGUs other than those we subcategorized are 
represented in the MACT floors for Hg and all types of EGUs are 
represented in the floors for the non-mercury HAP. Fluidized bed 
combustion EGUs are not an exception and such EGUs are found across the 
range of top performing EGUs for all of the HAP categories: Acid gas, 
non-mercury metallic, and Hg. In addition, any assertion that non-FBC 
EGUs are unable to meet the final standards because FBC EGUs are 
included in the same subcategory (or vice versa) is plainly refuted by 
the fact that EGUs of all types are currently meeting one or more of 
the final standards. Thus, the EPA finds no basis for subcategorizing 
FBC EGUs.
    Further, as noted below, the EPA does not believe there is a basis 
for subcategorizing small EGUs, either FBC or PC. In addition, the data 
have been re-evaluated based on comments received and an FBC unit is 
not the basis for the new source Hg MACT floor.
    Comment: Many commenters stated that the EPA should have considered 
additional subcategorization schemes, including one based on EGU size. 
Commenters noted that one of the factors that the Administrator can 
consider under CAA section 112(d)(1) in making subcategorization 
decisions is unit size. Commenters stated that an analysis of the 2010 
ICR data showed a statistical difference between EGUs with a capacity 
of 100 MW or less and EGUs above 100 MW; other commenters suggested 
that the cut-off range should be 125 MW. Although large in number 
(about 27 percent) of all EGUs, these small EGUs only comprise about 5 
percent of the coal-fired capacity in the U.S. Thus, commenters assert 
that if different MACT limits are set for this subcategory of EGUs, it 
will not have a significant impact on the health effects of HAP 
emissions. Commenters noted that although emission rates from such 
small EGUs are greater than those found in the large unit fleet, their 
contribution to the total EGU emissions is not significant. The costs 
associated with coming into compliance with the proposed rule by 
installing new controls would be proportionally much higher for these 
small EGUs than larger EGUs according to the commenters. The commenters 
allege that this would force the retirement of generation capacity and 
threaten electrical reliability without appreciable benefit to the 
environment.
    One commenter stated that in general, the nature of many public 
power facilities differs from the general population of coal-fired 
power plants. Public power units tend to be smaller in size, and are 
often space-constrained by growth in the community surrounding the 
generating unit since its initial construction. These limitations 
restrict the ability of these EGUs to achieve the same performance 
levels of larger,

[[Page 9398]]

unconstrained EGUs; and, for those EGUs that can comply with the 
proposed standards, the installation of controls sharply increases the 
cost of compliance. The commenter stated that the EPA did not 
adequately subcategorize to accommodate many small- and medium-sized 
public power utilities. In particular, the EPA did not avail itself of 
the opportunity to use a public power electric utility subcategory, 
rural subcategory, or fuel type subcategories. Other commenters 
endorsed the establishment of a less than 100 MW subcategory that would 
reduce the costs of the proposed rule significantly, but only affect 5 
percent of the total electric utility sector, and help minimize 
retirement of uneconomical plants.
    One commenter stated that the EPA properly recognized that 
subcategories based on unit size would be inappropriate because the 
proposed emission limits are in terms of lb/MMBtu or lb/TBtu and noting 
that an EGU's total nameplate capacity is wholly unrelated to its 
ability to achieve the proposed limits. Another commenter opposed any 
proposal to subcategorize units below 100 MW. The proposed rule does 
not apply to units less than or equal to 25 MW, and this commenter 
believed that this is a sufficient threshold for applicability.
    One commenter stated that the EPA could establish subcategories for 
the purpose of temporarily exempting, for example, a subcategory of 
utilities that meet the definition of small entity for purposes of the 
proposed rule. The temporary exemption would sunset on a date certain 
(e.g., 3 years from the effective date of the rule) at which point the 
sources in the subcategory would become subject to the rule, and a 
compliance timetable would start to run. The commenter believed that 
this time-staged promulgation and compliance proposal would greatly 
increase the chance that the control measures could be added in an 
orderly and efficient manner with minimal disruption to power markets 
and grid reliability.
    Response: The EPA agrees with commenters who stated that an EGU's 
size is totally unrelated to its ability to comply with the final 
concentration-based limits. The EPA examined the size of units within 
the respective MACT floor pools of sources and found units ranging in 
size from 25 to 1,320 MW in the HCl floor pool, from 25 to 869 MW in 
the non-mercury metallic floor pool, and from 47 to 544 MW in the Hg 
floor pool. Thus, we find no more difference between a 25 MW EGU and 
(e.g.) a 500 MW EGU than we do between a 500 MW EGU and a 1,300 MW EGU 
and reaffirm our position that the MW capacity of the EGU is not a 
determining factor in its emissions. Further, the EPA believes that 
units of all sizes are owned by both large and small entities.
    The EPA examined the effect if EGUs less than 125 MW were 
subcategorized for Hg. The resultant MACT floor for these EGUs would be 
1.0 lb/TBtu on a 30-boiler operating day rolling average, a level more 
stringent than that developed for the >8,300 Btu subcategory as a 
whole. We do not believe that this is what commenters envisioned when 
suggesting such a subcategory but we believe it confirms our analysis 
of the data that indicates, as noted, these units are controlled in the 
same manner as other, larger EGUs, such that additional 
subcategorization is not necessary or reasonable. Further, based on the 
number of EGUs less than 125 MW in the HCl and PM MACT floor pools, we 
believe that a similar analysis for HCl and PM would lead to similar or 
more stringent standards than without the additional subcategory. Thus, 
units of all sizes are capable of achieving the proposed limits and the 
EPA is not finalizing a subcategory based on unit size in the final 
rule.
    The CAA authorizes EPA to subcategorize based on ``classes, types, 
and sizes of sources.'' The EPA does not believe that this provision 
permits subcategorizing sources based solely on their status as small 
entities for several reasons. As a threshold matter, commenters 
provided no information to suggest that EGUs at small entities are 
different from EGUs owned by other entities. Instead, the commenters' 
justification for such a subcategory was that the costs to comply with 
the standards make it more difficult for small entities; thus, the 
basis is essentially a cost basis and we do not think that is 
consistent with the statute. Moreover, the legislative history of CAA 
section 112(d) supports EPA's interpretation that subcategories cannot 
be based on the cost of compliance. See S. Rep No. 101-228 at 166-67 (5 
Legislative History at 8506-07) (rejecting the implication that 
separate categories could be based on ``assertions of extraordinary 
economic effects'').
    In addition, the EGUs owned by small entities use the same type of 
fuel as other units, have the same type of combustor designs, and can 
use the same types of controls, and so there is no difference in the 
HAP emissions from such units. So, even if we believed a subcategory 
based on small entities was consistent with the statute, we would 
decline to include such a subcategory.
    Therefore, given the language of CAA section 112(d), the 
legislative history, and the available information, EPA is not creating 
a separate subcategory for EGUs owned by small entities.
    In addition, the D.C. Circuit has clearly stated that the EPA does 
not have the statutory authority under CAA section 112 to extend 
compliance dates past the 3-year maximum compliance time authorized in 
CAA section 112(i)(3)(A) except consistent with CAA sections 
112(i)(3)(B) and 112(i)(4). See NRDC v. EPA, 489 F.3d 1364, 1374 (D.C. 
Cir. 2007) (finding that ``Congress enumerated specific exceptions to 
the 3-year maximum, which indicates that Congress has spoken on the 
question and has not provided the EPA with authority under subsection 
112(i)(3)(B) to extend the compliance date * * *'') (citing also CAA 
section 112(i)(4)). The EPA may not alter the compliance date based on 
size or ownership considerations and, thus, we are not providing a 
separate compliance date for different groups of EGUs in the final 
rule.
    Comment: One commenter stated that the EPA should establish a 
subcategory consisting of EGUs that had received air construction 
permits but had not yet commenced construction as of the date of the 
EPA's proposed rule. The commenter believed that such a category would 
be justified because a substantial amount of time, money, and effort 
has been invested in these units. The commenter asserted that imposing 
new source standards on these EGUs for which the EPA's proposed rule 
had not been anticipated during their permit consideration would 
unreasonably and arbitrarily impose additional costs and burdens on 
these projects and would likely threaten the viability of many of them. 
The standards for this subcategory would be based on the anticipated 
performance of these units (as reflected by the permitted case-by-case 
emission levels), ensuring a reasonable and appropriate level of HAP 
control without unreasonably and arbitrarily interfering with the 
development of these units.
    Response: Clean Air Act section 112(a)(4) defines a new source as 
``a stationary source the construction or reconstruction of which is 
commenced after the Administrator first proposes regulations under this 
section establishing an emission standard applicable to such source.'' 
The EPA's regulations implementing the CAA section 112 General 
Provisions define ``commenced'' to mean ``with respect to construction 
or reconstruction of an

[[Page 9399]]

affected source, that an owner or operator has undertaken a continuous 
program of construction or reconstruction or that an owner or operator 
has entered into a contractual obligation to undertake and complete, 
within a reasonable time, a continuous program of construction or 
reconstruction.'' See 40 CFR 63.2.
    The EPA is constrained by the definition of ``new source'' such 
that any source that ``commenced'' construction after the May 3, 2011, 
proposal date is considered a new source under the statute and the 
source must comply with the new source standards even if the source 
received a final and legally effective CAA section 112(g) permit before 
proposal. It is unclear from the comments whether the sources 
identified in the comments have commenced construction as defined in 
the regulations; however, the identified sources are existing sources, 
not new sources, under the final rule if construction was commenced 
prior to the proposal date.
    Under the final rule, new sources must comply with the standards on 
the date of promulgation or at startup, whichever is earlier, and 
existing sources have 3 years to come into compliance with the final 
standards. Pursuant to the EPA's regulations at 40 CFR 63.44(b)(1), 
however, we may provide in a final CAA section 112(d) standard a 
specific compliance date for those sources that obtained a final and 
legally effective CAA section 112(g) case-by-case MACT standard and 
submitted the information required by 40 CFR 63.43 to the Agency before 
the close of the comment period. The EPA does not believe it has 
received such information during the comment period and we are not 
establishing a separate specific compliance period for sources that 
obtained final and legally effective CAA section 112(g) standards prior 
to promulgation of the final rule. In the absence of EPA action on this 
issue, state Title V permitting authorities are required to ``establish 
a compliance date in the [title V] permit that assures that the owner 
or operator shall comply with the promulgated standard [ ] as 
expeditiously as practicable, but not longer than 8 years after such 
standard is promulgated * * *'' 40 CFR 63.44(b)(2). Sources with final 
and legally effective section 112(g) standards should work with their 
permitting authorities to determine the appropriate compliance date 
consistent with the EPA regulations.
    Comment: One commenter stated that in accordance with CAA section 
112(d)(l), based on the government-to-government relationship of the 
Navajo Nation and the U.S. government, and consistent with the right of 
sovereignty and self-determination of the Navajo Nation, it may be 
appropriate to classify EGUs on tribal lands in a different subcategory 
from those on non-Indian lands. The commenter stated that in accordance 
with the distinctive status of Indian lands, based on principles of 
tribal sovereignty and self-determination, the government-to-government 
relationship, and the flexibility of federal agencies mandated under 
E.O. 13175, the EPA should classify sources on tribal lands as a unique 
subcategory of EGUs for which emission standards for NESHAP should be 
set pursuant to CAA section 112(d)(3).
    Response: Pursuant to CAA section 112(d)(1), the EPA may 
subcategorize sources based on differences in class, type, or size. In 
the preamble to the proposed rule, the EPA further explains that any 
basis for subcategorizing (e.g., class) must be related to an effect on 
emissions, rather than some difference which does not affect emissions 
performance. The EPA does not agree that a subcategory based on 
location on Tribal lands is consistent with the statutory authority to 
subcategorize, and commenters do not explain why emissions would be 
different for EGUs located on Tribal lands. Absent that showing, EPA 
believes it would not be appropriate to subcategorize units even if we 
believed such a subcategory is consistent with the statute. CAA section 
112 imposes specific requirements with respect to the methodology that 
the EPA must use in establishing emission standards for HAP, including 
Hg emissions from EGUs. Pursuant to CAA section 112(d)(1), the EPA may 
subcategorize sources based on differences in class, type, or size. The 
EPA believes, that any basis for subcategorizing (e.g., class) must be 
related to an effect on emissions, rather than some difference which 
does not affect emissions performance.
    However, the EPA is sensitive to the commenters' concerns and 
particularly recognizes the significance of Navajo Generating Station 
to the Central Arizona Project and the water delivery to tribes. As a 
result, EPA has been consulting with affected Indian tribes and working 
closely with other federal agencies, including the Department of the 
Interior, on these issues and intends to work with tribal and other 
authorities to ensure a smooth transition and address specific issues 
as they arise.
2. Oil Subcategories
    Comment: Several commenters stated that distillate oil, and in 
particular ultra-low sulfur diesel (ULSD) oil, has fuel characteristics 
closer to that of pipeline gas than to residual oils. The metals, as 
well as the ash and nitrogen content, of distillate oils are very low, 
and the sulfur content of ULSD is approximately the same as that of 
pipeline natural gas. The commenters state that distillate oil is a 
more refined product than residual oil and, thus, burns cleaner. 
According to commenters, separating liquid oil-fired EGUs into two 
subcategories (distillate and residual oil) would be consistent with 
the discussion of subcategory differentiation in the rule's preamble 
which indicates that the division of a category into subcategories is 
justified if the two subcategories have very different emissions, which 
is true for distillate vs. residual oils. Distillate and residual oils 
are also differentiated by their operating requirements. Some 
commenters stated that as a consequence of the mechanical differences 
between boilers designed for residual oil vs. distillate oils, and 
between the fuel-handling requirements for the different fuels, it is 
not possible to interchange oil types without significant modifications 
to the oil storage tanks, transfer pumps, piping and valves, flow 
control systems, burners, and burner control systems. Commenters also 
noted that some of the EGUs in the EPA's liquid oil-fired database were 
mischaracterized with regard to the type of oil burned during the 2010 
ICR testing.
    Some commenters alleged that by combining distillate and residual 
oil into a single MACT category, the resultant MACT standards cannot be 
satisfied by a boiler firing residual oil without substantial add-on 
controls. The commenters asserted that creation of separate 
subcategories for liquid oil-fired units that distinguish between 
residual and distilled oil would render the standards more achievable 
for distinct subcategories of EGUs and reduce the number of potential 
plant closures while still advancing the goal of reducing overall 
emissions. These commenters contend that MACT floors should not be used 
to eliminate whole classes of existing EGUs through mathematical floor 
calculations based on data from uncontrolled units and combining boiler 
subcategories that are not capable of accommodating a different fuel.
    One commenter stated that the EPA should not subcategorize liquid 
oil-fired EGUs based upon different grades of liquid oil. Although 
different grades of liquid oil may vary in their heat contents or 
viscosities, the commenter maintained that there is no indication in 
the rulemaking record that any physical

[[Page 9400]]

distinction among units burning different grades of liquid oil affects 
the nature or characteristics of emissions in a way that impacts the 
availability of controls. According to the commenter, both distillate 
and residual oil-fired units can apply similar control technologies to 
reduce HAP emissions, and EGUs firing these fuels do not have physical 
distinctions that prevent controls from operating effectively. The 
commenter believes that fuel switching is an appropriate control 
technology and is available for liquid oil-fired sources. Residual fuel 
oil contains higher levels of contaminants, including HAP, than 
distillate oil, and because a regulated entity can readily burn cleaner 
distillate oil in lieu of residual oil, it is inappropriate to 
subcategorize based on the distillation fraction of the liquid oil. 
Thus, according to the commenter, the grade of liquid-oil fuel does not 
provide a reasonable basis for subcategorizing various groups of liquid 
oil-fired EGUs. Another commenter alleges that the EPA did not list 
distillate oil-fired EGUs in the 2000 Finding.
    Response: The EPA has reviewed the data and determined that it is 
not necessary to subcategorize distillate vs. residual oil. Commenters 
had noted that the EPA's MACT Floor Analysis spreadsheet at proposal 
had erroneously assigned the oil type used during testing for some 
boilers. The EPA reviewed the data and determined that the submitting 
companies had entered the data incorrectly, or had indicated that two 
types of oil were fired in different parts of the 2010 ICR responses. 
The EPA contacted all of the companies with oil-fired EGUs in the 2010 
ICR to confirm the oil used during testing. Upon review of these data, 
it became apparent that units using residual oil with ESPs or 
distillate oil without control were the best-performing oil-fired EGUs 
for PM and the HAP metals. Further, although emissions of HAP from 
distillate oil-fired EGUs are generally lower than those from residual 
oil-fired EGUs, EGUs burning distillate oil appeared to have higher 
emissions of some HAP but lower emissions of others.
    In addition, the EPA does not agree that distillate oil-fired EGUs 
were not listed in the 2000 Finding. We believe it is inappropriate to 
exclude distillate oil-fired EGUs from regulation under the final rule 
because the Agency did not make a distinction when listing the oil-
fired units.
    The EPA also disagrees with commenters that by providing the 
distillate vs. residual oil subcategories as requested, the resultant 
standards would be more achievable. Were the EPA to subcategorize 
distillate oil from residual oil, the users of distillate oil would 
have no means of compliance other than obtaining ``compliance'' oil 
from their distributor (which was not indicated as an option by any 
commenter) or converting to natural gas and being removed from the 
subcategory. With no further subcategorization, oil-fired EGUs have the 
option of installing an ESP or converting to distillate oil for 
compliance. Commenters did not contend that it was impossible to 
convert to distillate oil, only that it would require plant 
modifications. Installing controls would also require plant 
modifications so sources will be able to evaluate the options and 
determine the most cost-effective option to comply with the final rule. 
CAA section 112 is intended to be a technology-forcing statute, and, 
because both distillate oil- and residual oil-fired EGUs were among the 
best performing sources in the floor and both types are meeting the 
final standards, we cannot reasonably conclude that the HAP emissions 
characteristics of these similar types of units are distinct. 
Therefore, the EPA is not establishing separate subcategories for 
distillate and residual oil-fired units in the final rule.
3. Limited-Use Subcategory
    Comment: Several commenters stated that EPA should establish a 
limited-use subcategory for liquid oil-fired EGUs that are required to 
burn oil during periods of natural gas curtailment. One commenter 
stated that under New York State Reliability Council Rules, their 
facility is required by the New York Independent System Operator 
(NYISO), for reliability purposes, to maintain the capability to burn 
oil and actually burn oil, from time to time, at varying load levels to 
help avoid or avert potential natural gas shortages in New York City. 
The requirements to burn oil under this program are mandatory and are 
not within the commenter's discretion. The reliability rules require 
that the commenter's EGUs maintain their co-firing capability to 
respond to unplanned, emergency scenarios by operating on oil during 
required minimum oil burn periods, typically 25 percent oil/75 percent 
natural gas. The commenter noted that operation using oil at other 
times or on 100 percent oil during reliability operation periods occurs 
very infrequently; with natural gas expected to become more available 
in future years, such an operating scenario will become less likely. 
However, while the reliability rules remain in place and commenter's 
boilers are required to operate under his regimen, the commenter 
believed that it is essential that it be able to do so.
    Other commenters noted that requiring installation of emission 
controls on oil-fired units that operate at a 10 percent oil-fired 
capacity factor or less is nonsensical and will result in little 
environmental benefit. Commenters contend that low-capacity factor 
units emit significantly less HAP than even well-controlled oil-fired 
units with much higher capacity factors. In addition, commenters allege 
that stack-testing at such units would be equally impractical and, in 
addition, would likely require the unit to operate on oil (and emit HAP 
just for the test) when it would otherwise be off-line or operating on 
natural gas.
    Response: As stated above, after considering comments received, we 
are establishing a limited-use subcategory for liquid oil-fired EGUs 
with an annual fired capacity factor of less than 8 percent averaged 
over each 24-month block period after the compliance date.
    At proposal, we solicited comment on establishing a limited-use 
subcategory for liquid oil-fired EGUs:

    EPA is also considering a limited-use subcategory to account for 
liquid oil-fired units that only operate a limited amount of time 
per year on oil and are inoperative the remainder of the year. Such 
units could have specific emission limitations, reduced monitoring 
requirements (limited operation may preclude the ability to conduct 
stack testing), or be held to the same emission limitations (which 
could be met through fuel sampling) as other liquid oil-fired units. 
EPA solicits comment on all of these proposed subcategorization 
approaches.

    As stated above, the EPA did not have sufficient information on 
limited-use liquid oil-fired EGUs upon which to base a subcategory at 
proposal. Some sources required to test under the ICR did not submit 
the data until after proposal. Commenters indicated that their units 
are different because many of them are only called to service to 
address reliability issues associated with, for example, natural gas 
curtailments. The commenters further indicated that their units are 
different because of the generally infrequent use and the sporadic, and 
at times frequent, start-up and shutdown periods (e.g., they are often 
only required to run for a couple of hours). These factors would lead 
to differences in the emissions characteristics for these units such 
that a numeric standard based on base load units would not likely be 
achievable during the very limited times that these limited use oil-
fired units operate.
    Based on comments received and our own analysis, we are finalizing 
a subcategory for limited-use liquid oil-

[[Page 9401]]

fired EGUs as indicated elsewhere in this preamble. We find that these 
units constitute a different class and type of units because they are 
generally only used to address reliability issues associated with, for 
example, natural gas curtailments, and because they in fact only run 
for very limited periods in a year on a seasonal basis.
    Although some commenters indicated a prevalence of natural gas/oil 
co-fired EGUs, the EPA also understands that there are other liquid 
oil-fired EGUs that do not co-fire natural gas but that could be 
subject to mandatory operation during periods of natural gas 
curtailment in their operating area if sufficient non-natural gas 
capacity is not available. Based on a review of units that report oil 
use to EPA, in 2010 there were 228 liquid oil-fired EGUs with a 
capacity factor of less than 5 percent and an additional 10 units with 
a capacity factor of between 5 percent and 10 percent. Only 2 of these 
units have capacity factors between 5 percent and 8 percent. This 
subcategory applies only to oil-fired EGUs that operate on oil alone 
and act as peaking units, as they generally address reliability issues. 
We are establishing the capacity factor threshold of 8 percent averaged 
over each 24-month block period after the compliance date.\320\ In 
addition, as discussed below, we are establishing work practice 
standard for this subcategory in lieu of numeric emission standards.
---------------------------------------------------------------------------

    \320\ Units that co-fire oil and natural gas where the oil 
combustion comprises 10 percent or less of the capacity factor are 
natural gas-fired EGUs that are not subject to this final rule.
---------------------------------------------------------------------------

    Commenters that requested a subcategory for these units noted the 
dichotomy of establishing a NESHAP to reduce emissions of HAP to the 
environment while at the same time requiring an EGU to run for the sole 
purpose of conducting emissions testing and thereby emitting those same 
HAP. Because the operation of these units is infrequent and 
unpredictable, performing testing to demonstrate that emission limits 
are being met requires the sources to be scheduled to be operated 
merely for the purpose of performing testing. We realize that similar 
situations occurred in the gathering of emissions data through the 2010 
ICR. However, unlike the case of one-time testing on a limited number 
of these units, such testing would be mandatory on a yearly basis for 
all of the EGUs upon the effective date of the final rule. Because 
requiring testing under this rule would in many cases require operators 
of these EGUs to schedule operation of these EGUs at times they would 
not otherwise run, it would result in both extra cost related to the 
testing as well as extra emissions; therefore, the Agency believes that 
it is technically and economically impracticable to monitor emissions 
for these EGUs, and that they should be subject to work practice 
standards that would not require emissions monitoring.
    The annual average capacity factor would be calculated on a 24-
month block period, commencing with the compliance date of the final 
rule. For example, assuming a March 1, 2015, compliance date, the first 
24-month block would commence on March 1, 2015, and end on February 28, 
2017, with the next 24-month block averaging period commencing on March 
1, 2017. We believe the 24-month averaging period is reasonable to 
account for the fact that units needed to address reliability issues 
(e.g., natural gas curtailment periods) will be called to service 
sporadically. A 24-month averaging period provides flexibility to 
ensure that these units can run if there are large periods when natural 
gas is unavailable. As explained above, the data shows that most of 
these units operate for less than 8 percent of the time, and in fact it 
is usually less than 5 percent. Therefore, when considering whether 
these units would be able to perform stack testing, in many cases this 
will be for units that in fact operate significantly less than 8 
percent of the time. In these cases, the EPA does not want to require 
the units to operate more just for the purpose of running a stack test 
resulting in additional pollution and cost. With projections for rising 
oil prices relative to natural gas prices, we expect this trend to 
continue. Liquid oil-fired EGUs subject to this subcategory would be 
required to conduct the same initial and periodic tune-up as all other 
affected units, but would have no other emission limit or work practice 
requirements.
    Although the EPA believes that the ability to burn oil up to 8 
percent of the time should address concerns about units that may need 
to operate using oil during gas curtailments. The EPA recognizes that 
if there were a period where gas use was more severely limited, such 
units might need the flexibility to operate for more than 8 percent in 
one year and less in the next, which is why we are providing the 2-year 
period; however based on the data we do not think EGUs in this 
subcategory will exceed even the 5 percent capacity factor that the 
data indicate is the average level for these sources.
4. Non-Continental Units
    Comment: Commenters from affected island EGUs requested that non-
continental EGUs be subcategorized from continental EGUs based on their 
lack of access to natural gas. The commenters urged the EPA to include 
a ``non-continental liquid oil'' subcategory in the final rule. 
According to the commenters, establishing a subcategory for non-
continental units is consistent with the approach the EPA has taken in 
past rulemakings, including the final Industrial Boiler NESHAP. Non-
continental EGUs have little or no access to natural gas, minimal 
control over the quality of available fuel, and disproportionately high 
operational and maintenance costs. All oil-fired EGUs operating in 
Hawaii, Guam, and Puerto Rico combust residual fuel oil exclusively and 
all are limited by the crude slates of their fuel suppliers. Island 
utilities can contract with suppliers for certain fuel specifications, 
such as sulfur content, pour point, flash point, API gravity and 
viscosity, which the refiners are able to meet primarily by blending 
and some sulfur removal during the refining process. However, the 
commenters state that the suppliers do not and cannot economically 
control for metal content. The crude slate feeding the refinery 
determines the HAP metal content of the residual oil produced according 
to the commenters. Because island utilities are dependent on local 
sources of fuel, they are equally limited by these factors.
    Two commenters believe that the separate non-continental 
subcategory should be expanded to include continental areas that are 
not interconnected with other utilities and have limited compliance 
options due to remote locations (e.g., Alaska).
    Response: The EPA agrees that the unique considerations faced by 
non-continental EGUs warrant a separate subcategory for these units and 
the data show that the difference in location causes a difference in 
emissions apparently due to the fuel that is available for such units; 
thus, the Agency has included such a subcategory in the final rule. At 
proposal, the EPA did not have all of the data from liquid oil-fired 
units in non-continental areas (e.g., Guam, Puerto Rico) and solicited 
comment on whether a subcategory should be established, based on the 
data to be received, for non-continental oil-fired EGUs. The EPA has 
now received these late data and, based on those data, is finalizing a 
non-continental subcategory for liquid oil-fired EGUs in Guam, Hawaii, 
Puerto Rico, and the U.S. Virgin Islands. The EPA is not aware of

[[Page 9402]]

any liquid oil-fired EGUs in any of the other U.S. territories that 
meet the CAA section 112(a)(8) definition but, if there are such units, 
they would also be part of the non-continental subcategory.
    The EPA agrees that the unique considerations faced by non-
continental refineries, including a limited ability to obtain 
alternative fuels that lead to different emissions characteristics, 
warrant a separate subcategory for these EGUs. The EPA believes that 
units in this subcategory will comply through the use of cleaner oils 
or, for PM, through the installation of an ESP. The EPA finds no merit 
in the comment that Alaska should be included in this non-continental 
subcategory because utilities in Alaska are not faced with the same 
access issues affecting island-based facilities.

C. Surrogacy

1. Filterable PM vs. Total PM
    Comment: Numerous commenters strongly objected to the use of total 
PM as the surrogate standard for non-mercury HAP metals. They argued 
that filterable PM is a better surrogate, especially given EPA's intent 
to use a PM CEMS for continuous compliance demonstration. Other 
commenters argued that we should not use a surrogate and instead should 
require direct compliance with a non-mercury HAP metals standard.
    Response: We have decided to use a filterable PM limit for the PM 
surrogate emission limit in the final rule.
    Although the objective of the emission limits we are establishing 
is to reduce the risks associated with HAP emissions, the limits are 
based in part upon the demonstrated capabilities of control 
technologies which are installed on existing sources. Except for Hg, 
the best PM controls provide the best controls of metal emissions. 
Emissions measurements of either filterable particulate, total 
particulate, individual metals, or total metals provide comparable 
indications that the best level of control is achieved. We can find no 
significant difference in the emissions that would be achieved by using 
any one of these emissions measurements.
    We re-assessed the relationships between individual metal 
emissions, filterable PM emissions, total PM emissions, and total 
PM2.5 emissions based on the test results provided through 
part III of the 2010 ICR. We compared the measured emissions of metals 
and PM with the uncontrolled emissions estimates and found that control 
of PM was indicative of the control of metals emissions. In addition, 
we compared the correlations associated with non-mercury HAP metal 
emissions and the three forms of PM and found that no specific 
particulate form provided a consistently superior indicator of better 
metals control. Although control of filterable PM provided the best 
indicator of performance for control of some HAP metals, control of 
total particulate or total PM2.5 was nearly as good as an 
indicator. For control of other HAP metals, total PM measurement 
provided the best indicator of control performance because it included 
the vapor-phase metal HAP, although, measurement of the control of 
filterable particulate was nearly as good an indicator. In addition, 
certain data analyzed by our Office of Research and Development 
indicate that a vapor-phase metal, such as Se, can be present as an 
acid gas and reduced significantly using acid gas technologies (wet and 
dry scrubbing). Given that the rule also provides for acid gas control 
monitoring, and the general equivalency of the different indicators, we 
have concluded that use of a filterable PM limit as the PM surrogate 
emission limit is appropriate.
2. Moisture Content of Oil
    Comment: A number of commenters stated that studies suggest that 
chloride in fuel oil can result from contamination during 
transportation and processing of crude oils and then be emitted as HCl 
during combustion. For example, the commenters asserted that the 
chloride contamination of crude oils can occur as a result of the 
ballasting of tanker ships with seawater. However, the Oil Pollution 
Act of 1990 requires all new oil tankers to be double hulled and 
establishes a phase out schedule (by the middle of the decade) for 
existing single hulled tankers with un-segregated ballasts. Because of 
the role of seawater contamination in introducing contaminants into the 
oil, the commenters suggest that the EPA set a percent water content 
limit for fuel oil at a level of 1.0 percent, rather than setting HCl 
and HF emissions limits. This would encourage handling and transport 
practices to limit salt water contamination. One commenter recommended 
a standard of 1.0 percent water because several of the lowest HCl and 
HF emitting units currently require percent water (or water and 
sediment) specifications between 0.5 percent and 1.0 percent.
    Response: The EPA is providing the alternative compliance assurance 
approaches in the final rule for liquid oil-fired EGUs of demonstrating 
compliance through either specific HCl or HF measurements or by 
demonstrating that the moisture content in the fuel oil remains at a 
level no more than 1.0 percent.
    The EPA is not aware of any FGD systems installed on oil-fired 
EGUs. Thus, it is only the quality of the oil, and the level of HAP 
constituents contained therein, that can be relied upon for ensuring 
compliance.
    In the proposal preamble, we stated:

    We believe that chlorine may not be a compound generally 
expected to be present in oil. The ICR data that we have received 
suggests that in at least some oil, it is in fact present. EPA 
requests comment on whether chlorine would be expected to be a 
contaminant in oil and if not, why it is appearing in the ICR data. 
To the extent it would not be expected, we are taking comment on the 
appropriateness of an HCl limit. See 76 FR 25045.

    Commenters refer to certain studies that provide a plausible reason 
for the chloride/fluoride contamination of fuel oils. We found this 
reason persuasive and accordingly are providing alternative compliance 
approaches in the final rule to demonstrate compliance with the acid 
gas HAP standards. Specifically, sources can demonstrate compliance 
through either specific HCl or HF measurements or by demonstrating that 
the moisture content in the fuel oil remains at a level no more than 
1.0 percent.

D. Area Sources

    Comment: Numerous comments were received both in support of and in 
opposition to the establishment of generally available control 
technology (GACT) standards for area source EGUs.
    Several commenters in opposition to area source standards stated 
that the EPA properly established emissions limitations based upon the 
performance of all EGUs, rather than distinguishing between major 
sources and area sources. The commenters believe that Congress did not 
intend the EPA to distinguish between ``major source'' EGUs and ``area 
source'' EGUs in determining whether and how to regulate EGUs under CAA 
section 112. These commenters indicated that differentiating major 
source and area source EGUs for purposes of setting emissions standards 
is inappropriate in light of the 2000 Finding regarding the threat 
posed by the absence of regulation of HAP emissions from EGUs. The 2000 
Finding was based upon studies whose conclusions regarding the impacts 
from EGU emissions did not depend upon any relevant distinction between 
major source and area source EGUs. The commenters note that segregating 
``major source'' and ``area source'' EGUs

[[Page 9403]]

would have the perverse effect of eliminating some of the best 
performing sources from the MACT pool of sources that constitute the 
``best performing'' 12 percent. Many of the best performing sources 
have employed control technology that brings their emissions below the 
major source threshold, despite the fact that they are larger units. As 
a result, the commenters believe that if the EPA created standards for 
``major source'' EGUs based only upon those units, the MACT standards 
for ``major source'' EGUs would be less stringent for each of the 
pollutants than proposed in this Rule. At the same time, the less 
polluting sources, the ``area source'' EGUs, could face limits more 
stringent than those proposed in the Rule. Commenters also note that 
after reviewing the substantial record in this rulemaking, they believe 
that the EPA has correctly determined that major and area source EGUs 
greater than 25 MW have similar HAP emissions and use the same control 
technologies and techniques to reduce HAP emissions. Thus, the 
commenters asserted that the record demonstrates that there is no 
technical basis for distinguishing between major and area source EGUs 
for purposes of establishing HAP emission control standards under CAA 
section 112(d).
    Many commenters in support of an area source designation for EGUs 
stated that the EPA has promulgated area source limits for many source 
categories of HAP emissions, including most recently industrial boilers 
and note that GACT controls have been used successfully in many other 
EPA MACT rules, including rules for iron & steel foundries, electric 
arc steelmaking, coatings operations, clay ceramics manufacturing, 
glass manufacturing, and secondary nonferrous metals manufacturing, in 
order to reduce costs and regulatory burdens. The commenters state that 
Congress has given the EPA the ability to subcategorize area sources 
because of their low HAP emissions and low potential impact on human 
health and that, contrary to the plain language of CAA section 112 and 
its legislative history, the EPA made no attempt in the proposed rule 
to distinguish between major sources and area sources for purposes of 
listing or setting standards. The commenters indicated that where 
Congress was concerned about the health impacts of specific pollutants 
from specific sources, it knew how to specify that MACT limits be 
promulgated (e.g., CAA section 112(c)(6)). The commenters state that 
area source rules would lessen the regulatory burden of a CAA section 
112 EGU rule on many small entities (arguing that many EGUs owned by 
small public power entities are area sources) and that as many as 12 
percent of the EGU population could qualify as area sources. A number 
of commenters pointed out that the small entity representatives (SER) 
on the SBREFA panel suggested that the EPA establish separate emission 
standards for EGUs located at area sources of HAP and that the 
standards be based on GACT as allowed under CAA section 112(d)(5). 
Specifically, the SERs recommended that the EPA establish management 
practice standards for area source EGUs.
    Response: The EPA is not establishing an area vs. major source 
distinction in the final rule.
    The CAA section 112(a)(8) definition of EGU does not distinguish 
between major and area sources, and we maintain that EGUs are a single 
source category that contains both major and area sources. The EPA 
proposed to regulate five subcategories of EGUs without distinguishing 
between major and area sources for purposes of establishing the 
standards for the different subcategories. Our approach is wholly 
consistent with the statutory definition of EGU and reasonable.
    Nevertheless, the Agency did examine whether to set separate 
standards for area source EGUs, because we do not believe that the 
statute prohibits the Agency from exercising its discretion to 
establish GACT standards for area sources pursuant to CAA section 
112(d)(5) if we determine such standards are appropriate. The EPA is 
not required, however, to establish GACT standards for area sources, 
and we believe it may even be unreasonable to do so under the 
circumstances we identified in the proposed rule as supported by the 
record of this final rule.
    At proposal, we determined that it was not appropriate to establish 
separate standards for major and area source EGUs, and even if we had 
exercised our discretion to set separate standards, we would have 
likely declined to exercise our discretion to set GACT standards for 
area source EGUs given our appropriate and necessary finding and the 
fact that a potentially large number of area source EGUs are in fact 
large well controlled units.
    Some commenters note that there could be as many as 12 percent of 
the total population that could be classified as area sources. We are 
not sure of the commenters' point in regard to this statement. As to 
commenters' statements that many of the area sources are municipal 
utilities, our information shows that many rather large EGUs (e.g., 
hundreds of MW) are also area sources, and the commenters have not 
provided any justification for establishing GACT standards for large 
synthetic area sources.
    Commenters did not provide an evaluation of the health and 
environmental impacts of the area sources and simply presume that the 
risks from such sources are lower, even though many of the same 
commenters noted that these smaller EGUs are often located in densely 
populated areas where populations are more likely to have adverse 
health effects from the HAP emissions. Furthermore, other commenters, 
including some industry commenters, noted that the vast majority of 
these potential area sources meet the criteria due to the installation 
of emission controls installed to meet other requirements. According to 
these commenters, these synthetic area sources would likely be able to 
meet the limits of this rulemaking and imposition of this rule would 
not appear to result in the installation of additional controls in a 
number of cases. We do not know if this assertion is correct but we 
determined approximately 69 coal-fired EGUs will be able to meet the 
existing source MACT standards with their current control configuration 
(out of 252 EGUs that reported data for Hg, PM, and HCl in the 2010 
ICR).
    Commenters also note that the Agency has exercised its discretion 
in other NESHAP rulemakings to establish area source limits. Although 
true, the fact that the EPA has established area source limits in some 
source categories is irrelevant to similar decisions for different 
source categories. Commenters have not shown that the circumstances 
applicable to those other source categories are similar to the 
circumstances identified for major and area source EGUs (e.g., similar 
controls, similar emission characteristics, large number of synthetic 
minor area sources). Further, those other source categories are not 
statutorily defined in a manner that includes both area and major 
sources. EGUs are the only source category defined in CAA section 112 
and, in establishing the definition of an ``electric utility steam 
generating unit'' under CAA section 112(a)(8), Congress included in the 
EGU source category both area and major sources. Thus, it is reasonable 
to regulate the EGU category in the manner Congress defined the 
category. Commenters have provided no legal support for the contention 
that the EPA must regulate area and major sources in the same category 
in separate rulemakings, and the EPA has in fact regulated both major 
and area sources in

[[Page 9404]]

the same rulemaking even absent a statutory definition that includes 
both major and area sources. (See National Emission Standards for 
Hazardous Air Pollutants From the Portland Cement Manufacturing 
Industry and Standards of Performance for Portland Cement Plants; 75 FR 
54970; September 9, 2010.)
    The EPA considered the totality of the circumstances when 
determining whether to set separate area and major source standards for 
EGUs and also considered whether it would be reasonable to establish 
GACT standards for areas sources. We reasonably considered whether 
emissions characteristics of major and area sources are different when 
determining whether to establish GACT standards, notwithstanding 
commenters' assertion that such consideration is not correct. That we 
also consider emission characteristics in subcategorization decisions 
is of no consequence for area source decisions. Given that the 
statutory definition of EGUs contains both major and area sources, it 
was reasonable to evaluate whether there were sufficient differences 
between area and major sources when deciding whether to exercise our 
discretion to set separate area and major source standards.
    In addition, we find commenter's point concerning CAA section 
112(c)(6) odd because EGUs emit several of the CAA section 112(c)(6) 
HAP (e.g., lead, Hg). Although EGUs were exempted from that provision, 
the fact that they emit some of the HAP called out for MACT control 
supports our decision to not establish GACT standards for any EGUs. CAA 
section 112(d)(5) leaves it to the Agency's discretion to determine 
whether GACT standards should be established for area sources, and the 
statute does not require GACT standards or even indicate that such 
standards are to be the default regulatory approach for area sources. 
See 76 FR 25021. Instead, the statute provides the Agency with 
discretion and we have exercised it reasonably in this case.
    Commenters indicate that many EGUs owned by small entities are 
potential area sources. However, commenters fail to note that there are 
also EGUs owned by small entities that are not potential area sources, 
and, thus, would not accrue any ``lessened regulatory burden'' benefit 
from a decision by the EPA to establish area source standards.
    Some commenters state that the EPA's mere assertion that there 
would be no difference between GACT and MACT to justify an area source 
finding does not provide sufficient documentation for the decision. But 
EPA did not say there would be no difference between MACT and GACT. 
Instead, it stated that it would be difficult to make a distinction 
given the similarities between the EGUs and major and area source 
facilities. Specifically, as noted by other commenters, and observable 
by a review of the MACT Floor Analysis spreadsheets, potential area 
sources range in size from units near the CAA section 112(a)(8) defined 
lower size limit to units of hundreds of megawatts. Further, these 
larger area source units are, for the most part, controlled with the 
full suite of emission control technologies available (e.g., fabric 
filters, scrubbers).
    In addition, the data that were available in the docket for the 
proposed rule show that there is little difference between major and 
area source EGUs individually, and that generally the driver for 
whether a utility facility is a major or area source depends on the 
number of EGUs located at a facility (almost exclusively one or two 
EGUs located at area sources), not on any inherent difference between 
the EGUs themselves. See ``Evaluation of Area Source EGUs'' TSD, Docket 
EPA-HQ-OAR-2009-0234. In fact there are a number of EGUs that are quite 
large that are area sources and others that are small that are major 
sources. Id. This is the case because the acid gas HAP emissions are 
what drive EGUs to have HAP emissions exceeding the major source 
threshold. With a few exceptions, the EGUs located at area sources have 
FGD or other acid gas controls that reduce the acid gas HAP to area 
source levels. Id. Thus, the majority of sources that currently qualify 
as area sources were, in fact, major sources prior to installing 
controls. The exceptions are those units that would likely be able to 
achieve the MACT level of control for acid gas with minimal use of DSI 
at a reasonable cost. Id.
    In addition, the data show that a number of area sources for which 
we have data are high emitters of Hg and non-Hg metal HAP. Id. Pursuant 
to our appropriate and necessary finding, these HAP pose a significant 
threat to human health. Thus, even were we to distinguish between major 
and area sources, which we do not believe is appropriate given the 
similarities between such sources, we would still decline to set GACT 
standards, and as such we maintain that MACT standards are appropriate. 
Moreover, for acid gas HAP, as discussed above, the data indicate that 
the level of control would likely be the same even if we did establish 
GACT standards under CAA section 112(d)(5).
    We fully evaluated the nature of EGUs, and we do not see a basis on 
which to distinguish these sources for purposes of setting standards. 
Thus, we maintain that we reasonably exercised the discretion afforded 
the Agency under the statute and declined to set separate standards for 
area source EGUs.

E. Health-Based Emission Limits

    Comment: Many commenters noted that in the proposed rule the EPA 
considered whether it was appropriate to exercise its discretionary 
authority to establish health-based emission limits (HBEL) under CAA 
section 112(d)(4) for HCl and other acid gases and proposed not to 
adopt such limits, citing, among other things, information gaps 
regarding facility-specific emissions of acid gases, co-located sources 
of acid gases and their cumulative impacts, potential environmental 
impacts of acid gases, and the significant co-benefits estimated from 
the adoption of the conventional MACT standard. Comments were received 
both supporting this position and refuting it. Several commenters 
suggested legal, regulatory and scientific reasons for why HBEL for HCl 
might be appropriate for this MACT standard. With respect to legal 
concerns, some commenters indicated that CAA section 112(d)(4) 
establishes a mechanism for the EPA to exclude facilities from certain 
pollution control regulations and circumstances when these facilities 
can demonstrate that emissions do not pose a health risk. Commenters 
cited a Senate Report that influenced development of CAA section 
112(d)(4), where Congress recognized that, ``For some pollutants a MACT 
emissions limitation may be far more stringent than is necessary to 
protect public health and the environment.'' (Footnote: S. Rep. No. 
101-128 (1990) at 171.) Commenters also cited regulatory precedent for 
addressing HCl as a threshold pollutant, including the Hazardous Waste 
Combustors and the Chemical Recovery Combustion Sources at Kraft, Soda, 
Sulfite, and Stand-Alone Semichemical Pulp Mills NESHAP. Commenters 
requested that the EPA incorporate the flexibility afforded by CAA 
section 112(d)(4) and allow sources reasonable means for demonstrating 
that their respective emissions do not warrant further control. The 
commenters also cited the 2004 vacated Boiler MACT as precedent for 
HBEL for HCl. The commenters contended that the EPA failed to explain 
why the health-based emissions limitations it established in the 2004 
Boiler MACT and the justification provided for those limitations could 
not be used in this case. The commenters also cited a 2006

[[Page 9405]]

court briefing where the EPA vigorously defended the HBEL included in 
the 2004 Boiler rule when it was challenged in the D.C. Circuit (Final 
Brief For Respondent U.S. Environmental Protection Agency, D.C. Cir. 
Case No. 04-1385 (Dec. 4, 2006) at 59-65, 69).
    Other commenters stated that on August 6, 2010, the EPA adopted a 
NESHAP for Portland Cement plants that specifically rejected adoption 
of risk-based exemptions or HBEL for HCl and manganese (Mn). These 
commenters argue there are no differences sufficient to warrant a 
reversal of that decision in the EGU MACT standard. The commenters 
raised concerns that health risk information cited by the EPA for HCl, 
HF, and hydrogen cyanide (HCN) does not establish ``an ample margin of 
safety'' and, therefore, no health threshold should be established. The 
commenters believe risk-based exemptions at levels less stringent than 
the MACT floor are prone to lawsuits that could potentially further 
delay implementation of the EGU MACT.
    Some commenters disagreed with using a hazard quotient (HQ) 
approach to establish a risk-based standard because the HQ would not 
account for potential toxicological interactions. The commenter noted 
that an HQ approach incorrectly assumes the different acid gases affect 
health through the same health endpoint, rather than assuming that the 
gases interact in an additive fashion. This commenter suggested that a 
hazard index approach, as described in the EPA's ``Guideline for the 
Health Risk Assessment of Chemical Mixtures,'' would be more 
appropriate.
    Some commenters dispute that emissions from other EGUs or source 
categories should be considered when developing an HBEL and they argued 
that Congress expected the EPA to consider the effect of co-located 
facilities during the CAA section 112(f) residual risk program instead 
of under CAA section 112(d). Commenters added that there is no prior 
EPA precedent for considering co-located facilities from a different 
source category during the same CAA section 112 rulemaking.
    Several commenters disputed the EPA's consideration of non-HAP 
collateral emissions reductions in setting MACT standards. They 
contended that the EPA's sole support for its ``collateral benefits'' 
theory is legislative history--the Senate Report that accompanied 
Senate Bill 1630 in 1989 and noted that the D.C. Circuit rejected this 
use of this theory since the Senate Report referred to an earlier 
version of the statute that was ultimately not enacted. Instead 
commenters suggested that other components of the CAA, such as the 
National Ambient Air Quality Standards (NAAQS), are more appropriate 
avenues for mitigating emissions of criteria pollutants.
    Several other commenters suggested it is impossible to assess an 
established health threshold for HCl such that a CAA section 112(d)(4) 
standard could be set without evaluating the collateral benefits of a 
MACT standard. And, as described in the recently finalized cement kiln 
MACT rule, setting technology-based standards for HCl will result in 
significant reductions in the emissions of other pollutants, including 
SO2, Hg, and PM. The commenter added that these reductions 
will provide enormous health and environmental benefits, which would 
not be experienced if CAA section 112(d)(4) standards had been 
finalized. These commenters contended that HCl and other dangerous acid 
gases produced by EGUs pose substantial risks to industrial workers, as 
well as surrounding communities, and must be limited by the strict 
conventional MACT standards.
    Several commenters indicated that the current economic climate 
requires the EPA to balance economic and environmental interests and 
indicated that HBEL would help target investments into solving true 
health threats where limits are no more or less stringent than needed 
to protect public health. Many commenters provided estimates of 
compliance cost savings if an HBEL is included in this final rule. Some 
commenters stressed the importance of an HBEL for small entities 
affected by the regulations. Several other commenters suggested that 
the EPA should estimate the costs and environmental effects of the HBEL 
option compared to a conventional MACT standard in order to make an 
informed decision on the adoption of HBEL.
    Response: After considering the comments received, the EPA has 
decided not to adopt an emissions standard based on its authority under 
CAA section 112(d)(4) for all the reasons set forth in the proposed 
rule.
    The EPA notes that the Agency's authority under CAA section 
112(d)(4) is discretionary. That provision states that the EPA ``may'' 
consider establishing health thresholds when setting emissions 
standards under CAA section 112(d). By the use of the term ``may,'' 
Congress clearly intended to allow the EPA to decide not to consider a 
health threshold even for pollutants which have an established 
threshold. As explained in the preamble to the proposed rule, it is 
appropriate for the EPA to consider relevant factors when deciding 
whether to exercise its discretion under CAA section 112(d)(4), and, 
notwithstanding commenters' assertions to the contrary, the 
considerations we include in our analysis are reasonable. The EPA has 
considered the public comments received and is not adopting an 
emissions standard under CAA section 112(d)(4) for the reasons set 
forth in the proposed rule and explained below. We note that this 
action is consistent with EPA's recent decisions not to develop 
standards under CAA section 112(d)(4) for the Industrial, Commercial 
and Institutional Boilers and Process Heaters and the Portland Cement 
source categories.
    As explained in the preamble to the proposed rule, the EPA 
continues to believe that the potential cumulative public health and 
environmental effects of all acid gas HAP emissions, not just HCl 
emissions, from EGUs and other acid gas sources located near EGUs 
supports the Agency's decision not to exercise its discretion under CAA 
section 112(d)(4). Additional data for all acid gas emissions were not 
provided during the comment period, and the data already in hand 
regarding these emissions are not sufficient to support the development 
of emissions standards for EGUs under CAA section 112(d) that take into 
account the health threshold for acid gas HAP, particularly given that 
the Act requires the EPA's consideration of health thresholds under CAA 
section 112(d)(4) to protect public health with an ample margin of 
safety. We note here that EPA agrees with the commenter who pointed out 
that a better way to evaluate the potential health impact interactions 
of all acid gases would be to use the approach in EPA's ``Guideline for 
the Health Risk Assessment of Chemical Mixtures'' rather than a simple 
evaluation of individual HQ values for each acid gas, but we further 
note that use of such an approach requires a substantially greater 
knowledge of acid gas emissions than is currently available. We further 
note that, even if cost were a relevant factor in setting standards 
under CAA section 112(d)(4), since the data are not available that 
would allow us to develop an acid gas HBEL appropriate to protect 
public health with an ample margin of safety, we cannot determine 
whether such standards would have any cost savings associated with them 
or not. In addition, the concerns expressed by the EPA in the proposal 
regarding the potential environmental impacts and the cumulative 
impacts of acid gases on public health were not assuaged by the

[[Page 9406]]

comments received because no significant data regarding these impacts 
were received.
    The EPA also received comments recommending not only that the EPA 
establish emissions standards for acid gases pursuant to CAA section 
112(d)(4), but that it do so by excluding specific facilities from 
complying with emissions limits if the facility demonstrates that its 
emissions do not pose a health risk. The EPA does not believe that a 
plain reading of the statute supports the establishment of such an 
approach. Although CAA section 112(d)(4) authorizes the EPA to consider 
the level of the health threshold for pollutants which have an 
established threshold, that threshold may be considered ``when 
establishing emissions standards under [CAA section 112(d)].'' 
Therefore, the EPA must still establish emissions standards under CAA 
section 112(d) even if it chooses to exercise its discretion to 
consider an established health threshold. A source-by-source standard 
is not mandated as some commenters seem to imply, and we are unsure how 
we could reasonably implement such an approach even if we determined 
such an approach was legally available. For these reasons alone, we 
concluded it was not appropriate to exercise our discretion to 
establish section 112(d)(4) standards for acid gas HAP emissions.
    In addition, as explained in the preamble to the proposed rule, the 
EPA also considered the co-benefits of setting a conventional MACT 
standard for HCl. The EPA considered the comments received on this 
issue and continues to believe that the estimated co-benefits are 
significant and provide an additional basis for the Administrator to 
conclude that it is not appropriate to exercise her discretion under 
CAA section 112(d)(4). The EPA disagrees with the commenters who stated 
that it is not appropriate to consider non-HAP benefits in deciding 
whether to invoke CAA section 112(d)(4). Although MACT standards may 
directly regulate only HAP and not criteria pollutants, Congress did 
recognize, in the legislative history to CAA section 112(d)(4), that 
MACT standards would have the collateral benefit of controlling 
criteria pollutants as well and viewed this as an important benefit of 
the air toxics program. See S. Rep. No. 101-228, 101st Cong. 1st sess. 
at 172. The EPA consequently does not accept the argument that it 
cannot consider reductions of criteria pollutants in determining 
whether to take or not take certain discretionary actions, such as 
whether to adopt an HBEL under CAA section 112(d)(4). There appears to 
be no valid reason that, in situations where the EPA has discretion in 
what type of standard to adopt, the EPA must ignore controls which 
further the health and environmental outcomes at which CAA section 
112(d) is fundamentally aimed because such controls not only reduce HAP 
emissions but emissions of other air pollutants as well. Thus, the 
issue being addressed is not whether to regulate non-HAP under CAA 
section 112(d) or whether to consider other air quality benefits in 
setting CAA section 112(d)(2) standards--neither of which the EPA is 
doing--but rather whether EPA may exercise its discretion to regulate 
certain HAP based on the MACT approach and consider collateral health 
and environmental benefits when choosing whether to exercise that 
discretion. The EPA believes there is no legal principle that precludes 
it from doing so and commenters have not provided one.

F. Compliance Date and Reliability Issues

    Comment: Multiple commenters asked that the compliance date be 
clearly stated as soon as possible, as well as that guidance be 
provided for utilities unable to comply with the stated timelines, to 
allow time for utilities to prepare for compliance. Commenters also 
asked that any decisions or policies on extensions be published in a 
rulemaking. In addition, commenters requested that the EPA establish, 
streamline, and simplify the process of applying for the 1-year 
extension under CAA section 112(i)(3).
    Multiple commenters offered suggestions on methods for allowing 
more time for compliance, including EPA's authority under CAA section 
112(n)(1)(A); state authority under CAA section 112(i)(3); Presidential 
authority under CAA section 112(i)(4); categorical extensions for 
publicly-owned or governmental facilities according to EO 13132, 13563, 
and UMRA of 1995; state-designed programs under the delegation 
provisions of CAA section 112; various Consent Decrees; Administrative 
Orders of Consent (AOCs); temporary waiver mechanisms; and adoption of 
MACT compliance schedules through minor permit modifications of a 
source's Title V federal operating permits. Absent such considerations 
for additional compliance time, many commenters suggested that the 
reliability of the nation's electric grid would be jeopardized as 
utility companies were forced to retire EGUs because they could not 
install the needed controls in the requisite time.
    Compliance times requested by commenters ranged from 1 additional 
year (4 years total) to 6 additional years (9 years total). Multiple 
commenters requested that a utility be required to demonstrate good 
faith progress toward compliance to get any extension. Some commenters 
suggested that the EPA require utilities to submit a notice concerning 
which EGUs will be retrofitted or retired within 1 year of the 
effective date; that the compliance date align with the Power Year used 
by RTOs; and that the EPA clarify that retirement and any clean 
replacement power that complies with the NESHAP rule, including off-
site combined heat and power and waste heat recovery, can be deemed 
``controls'' under the CAA.
    Commenters noted the specific situations related to small entities 
and their inability to compete with the larger, investor-owned 
utilities for financing and engineering and technical labor as well as 
the different process they need to follow for capital improvements. 
Multiple commenters asked that the EPA consider other simultaneous 
rulemakings (e.g., Cooling Water Intake Structures; Coal Combustion 
Residuals; CSAPR, etc.) and extend the compliance period. Many 
commenters noted these other requirements and suggested that 
installation of the necessary controls could not be completed within 
the compliance period allowed under CAA section 112, even if a fourth 
year were to be granted by the permitting authority, citing examples of 
the times necessary for installation of various pieces of control 
equipment or replacement power.
    Some commenters pointed to existing state programs (e.g., Colorado, 
Oregon, Washington) and indicated that if states can demonstrate that 
overall emissions reductions would be equivalent or greater than those 
that would be achieved by the proposed rule, the EPA should delegate 
the CAA section 112 program to these states, even if the state 
emissions reductions would not necessarily occur on the same schedule 
(many state programs call for retirement of EGUs in years beyond the 
CAA section 112 compliance date). The commenters did not want the 
promulgation of the final rule to undermine the significant amount of 
work that may have been invested in creating state-specific programs to 
curb emissions within a reasonable timeframe. The commenters seek to 
make use of temporal flexibility, authorized under CAA section 
112(i)(3), in obtaining delegation of the final rule to preserve the 
hard-negotiated comprehensive state-specific programs designed to yield 
greater emission reductions than the MATS alone.

[[Page 9407]]

    Other commenters requested that no additional time be granted for 
compliance. These commenters reference a number of reports (e.g., by 
the URS Corporation, by M.J. Bradley & Associates and the Analysis 
Group, and by the Bipartisan Policy Center) to indicate that not only 
is technology readily available, but that the technology can typically 
be installed in less than 2 years and that the electric industry is 
well-positioned to comply with the EPA's proposed air regulations 
without threatening electric system reliability. Commenters assert 
that, if electric system reliability were to be threatened in local 
areas as a result of the rule, the EPA has the statutory authority to 
grant, on a case-by-case basis, extensions of time to complete the 
installation of pollution control systems. One commenter stated that no 
additional controls would need to be installed in many cases and any 
coal unit should be able to comply with all of the standards. Another 
commenter noted that utilities that failed to plan ahead ``should not 
be permitted to use their own inaction to justify more time.'' 
Commenters noted that several major utility companies have anticipated 
the EPA's rules and are already taking action to ensure a reliable 
supply of electricity in their service territory and beyond. Other 
commenters agree that there is significant excess generation capacity 
in the country and reliability will not be threatened by the rule. 
According to one commenter, companies are already preparing for a 2015 
compliance date, factoring in the capital expenditures required to 
comply and delays would undermine decisions that have already been 
made. Commenters cite, for example, recent electricity forward capacity 
market auctions in the PJM market for the period of 2014 and 2015 that 
indicate that the capacity markets cleared with electricity reserve 
margins of 20 percent; this is in excess of the default reliability 
targets used by the North American Electric Reliability Corporation 
(NERC) for the year 2015. One commenter quoted NERC, stating that NERC 
does not see impacts from proposed climate legislation or anticipated 
EPA regulation as a reliability concern. Another commenter noted that 
the Building and Construction Division of the AFL-CIO has stated that 
there is no evidence to suggest that the availability of skilled 
manpower will constrain pollution control technology installation. In 
fact, according to the commenter, given the high levels of unemployment 
in the construction sector, these jobs are much needed.
    A number of commenters expressed concern that the time frame for 
compliance with a regulation under CAA section 112(d) was too short for 
this industry and would result in compromising the reliability of 
electricity supply. Commenters asserted that reliability would be 
compromised in several ways: (1) EGUs might have to temporarily close 
if the owner or operator is unable to install controls on the unit 
within the 3-year time frame or 3 years plus one; (2) the timing of 
outages to install controls will cause short term closures that could 
threaten grid stability; (3) owner/operators may shut down EGUs rather 
than invest in retrofits to keep them running and that these closures 
may cause a loss of critical generation; and (4) the construction of 
replacement generation or implementation of other measures to address 
reliability concerns due to plant retirements could take longer than 3 
years, and that units slated for closure may be necessary beyond the 3-
year compliance period but will be unable to run because they have not 
installed the necessary controls.
    Response: Clean Air Act section 112 specifies the dates by which 
affected sources must comply with this rule. New or reconstructed units 
must be in compliance immediately upon startup or the effective date of 
this rule, whichever is later. Existing sources may be provided up to 3 
years after the effective date to comply with the final rule; if an 
existing source is unable to comply within 3 years, a permitting 
authority has the ability to grant such a source up to a 1-year 
extension, on a case-by-case basis, if such additional time is 
necessary for the installation of controls.
    As is explained earlier in this preamble, the 3-year compliance 
window is based on the date that is 60 days after publication of this 
rule in the Federal Register. Because publication doesn't occur until 
several weeks after the rule is signed by the Administrator, the 
earliest required date for compliance would be sometime in March 2015. 
Because the last stage of control installations usually needs to occur 
when the unit is off-line and because scheduled outages are usually 
scheduled for the spring or fall months when peak electric demand is 
lower, this additional time is significant as it provides companies an 
additional outage period, the spring of 2015, to install controls.
    The EPA has considered the concerns raised by commenters and has 
concluded that given the flexibilities further detailed in this 
section, the requirements of the final rule for existing sources can be 
met by most sources without adversely impacting electric reliability. 
In particular, EPA believes that the flexibility of permitting 
authorities to allow a fourth year for compliance should be available 
in a broad range of situations (as discussed below), and that this 
flexibility addresses many of the concerns that have been raised. 
Furthermore as indicated below, in the event that an isolated, 
localized concern were to emerge that could not be addressed solely 
through the 1-year extension under CAA section 112(i)(3), the CAA 
provides flexibilities to bring sources into compliance while 
maintaining reliability.
    The EPA considered the impact that potential retirements in 
response to this rule will have on resource adequacy in order to gauge 
the rule's impact on reliability. In considering these impacts, the EPA 
considered both the analysis it has conducted as well as analyses 
conducted by a number of other groups. The EPA's analysis shows that 
the expected retirements of coal-fueled units as a result of this final 
rule (4.7 GW) are fewer than was estimated at proposal and much fewer 
than some have predicted.\321\ The net capacity reductions projected by 
the EPA make up less than one-half of one percent of the total 
generating capacity in the U.S. and about one and one-half percent of 
U.S. coal capacity. Because concerns have been raised that the use of 
DSI may not be as prevalent as the Agency has predicted and because 
this could lead to more coal retirements, the Agency also performed a 
sensitivity analysis in which fewer DSI systems and more scrubber 
systems were installed. In that sensitivity, we see approximately 1 
more GW of retirements. This small change would have only a very small 
potential impact on resource adequacy. When considering the impact that 
one specific action has on power plant retirements, it is important to 
understand that the economics that drive retirements are based on 
multiple factors including: expected demand for electricity, the cost 
of alternative generation, and the cost of continuing to generate using 
an existing unit. The EPA's analysis shows that the lower cost of 
alternative fuels, particularly natural gas, as well as reductions in 
demand, will have a greater impact on the

[[Page 9408]]

number of projected retirements than will the impact of this final 
rule.
---------------------------------------------------------------------------

    \321\ The EPA's analysis also identifies a small amount of 
capacity loss (less than 0.7 GW) due to derating of certain units, 
as well as partially offsetting reductions in non-coal retirements 
in comparison with the base case. The net estimated reduction in 
capacity, in comparison with the base case, is estimated at less 
than 5 GW.
---------------------------------------------------------------------------

    The EPA's assessment looked at the capacity reserve margins in each 
of 32 subregions in the continental U.S. Demand forecasts used were 
based on EIA projected demand growth. The analysis shows that with the 
addition of very little new capacity, average reserve margins are 
significantly higher than required. The NERC assumes a default reserve 
margin of 15 percent while the average capacity margin seen after 
implementation of the policy is nearly 25 percent. Although such an 
analysis does not address the potential for more localized reliability 
concerns associated with transmission constraints or the provision of 
location-specific ancillary services (such as voltage support and black 
start service), the number of retirements projected suggests that the 
magnitude of any local reliability concerns should be manageable with 
existing tools and processes.
    Several outside analyses have reached conclusions consistent with 
EPA's analysis. The DOE, in December 2011, published a report that 
looked at resource adequacy in the bulk power system when faced with a 
stress test which was a regulatory scenario far more stringent than 
EPA's regulations.\322\ For this stress test, in addition to CSAPR and 
MATS requirements, each uncontrolled electric generator is required to 
install both a wet FGD system and a fabric filter to reduce air toxics 
emissions. If such installations are not economically justified, this 
scenario assumes that the plant must retire by 2015. In reality, as 
discussed previously, power plant owners will have multiple other 
technology options to comply with the regulations--options that 
typically cost less than installations of FGDs and fabric filters. The 
analysis finds that target reserve margins can be met in all regions, 
even under these stringent assumptions. Moreover, in every region but 
one (TRE), no additional new capacity is needed. In TRE, the analysis 
finds that less than 1 GW of new natural gas capacity would be needed 
by 2015 beyond the additions already projected to occur in the 
Reference Case. This analysis also finds that the total amount of new 
capacity that would be added by 2015 is less than the amount that is 
already under development.
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    \322\ U.S. Department of Energy, December 2011, ``Resource 
Adequacy Implications of Forthcoming EPA Air Quality Regulations.''
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    In June 2011, the Bipartisan Policy Center issued a report 
analyzing potential collective impacts of EPA's pending power sector 
rules and concluding that ``scenarios in which electric system 
reliability is broadly affected are unlikely to occur.'' \323\
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    \323\ Bipartisan Policy Center, June 2011, ``Environmental 
Regulation and Electric System Reliability.''
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    In August 2011, PJM Interconnection--the Regional Transmission 
Operator (RTO) responsible for planning and reliable operation of the 
bulk power system serving all or portions of 13 states in the Mid-
Atlantic and Midwestern regions--issued a report analyzing the impacts 
of the CSAPR and the proposed MATS rule.\324\ Although PJM's analysis 
assumes substantially more retirements than EPA projects, it 
nevertheless concludes that resource adequacy is not threatened in the 
PJM region. This is particularly significant, given that the PJM region 
is one of the largest and most heavily dependent on coal-fueled 
generation in the country. The PJM analysis notes, as EPA has 
acknowledged, that even where there is adequate generation capacity on 
a regional basis, localized reliability issues may emerge in connection 
with retirements that may need to be addressed.
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    \324\ PJM Interconnection, August 26, 2011, `` Coal Capacity at 
Risk for Retirement in PJM: Potential Impacts of the Finalized EPA 
Cross State Air Pollution Rule and Proposed National Emissions 
Standards for Hazardous Air Pollutants.''
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    The EPA has reviewed industry and NERC studies suggesting, contrary 
to the EPA's and these other groups' analyses, that EPA rules affecting 
the power sector (including this final rule, the CSAPR, EPA's proposed 
rule addressing power plant cooling water intake systems under section 
316(b) of the Clean Water Act (CWA), and EPA's proposed rule addressing 
coal combustion residuals under the Resource Conservation and Recovery 
Act) will result in substantial power plant retirements. Some of these 
studies predict that such levels of retirements will have adverse 
effects on electric reliability in some regions of the country. 
Although the specifics of these analyses differ, in general they share 
a number of serious flaws in common that call their conclusions into 
question.
    First, most of these studies make assumptions about the 
requirements of the EPA rules that are inconsistent with, and 
dramatically more expensive than, the EPA's actual proposals or final 
rules. For example, a large proportion of the retirements projected by 
several of these studies is attributable to their inaccurate assumption 
that EPA's cooling water intake rule under CWA section 316(b) would 
require all or virtually all existing power plants to install cooling 
towers. In one study, the reliability effects reported are based on 
inaccurate assumptions that all existing EGUs with a capacity 
utilization factor of less than 35 percent would close, and that all 
in-scope electric generators would be required to install cooling 
towers within 5 years, whereas the not-selected options with closed 
cycle cooling in EPA's proposal envisioned that permit authorities 
could exercise discretion to allow facilities 10 to 15 years' time to 
comply. In most cases, these analyses were performed before the CWA 
section 316(b) rule or the MATS rule were even proposed; even analyses 
subsequent to the CWA section 316(b) proposal continue to inaccurately 
portray EPA's proposed approach.
    Second, in reporting the number of retirements, many analyses fail 
to differentiate between plant retirements attributable to the EPA 
rules and retirements of older, smaller, and less efficient plants that 
are already scheduled for retirement because owners have made business 
decisions, based in significant part on market conditions, not to 
continue operating them.
    Third, most of these analyses fail to account for the broad range 
of responses available to address electric reliability concerns 
associated with power plant retirements, including upgrades to the 
transmission system, construction of new generation, and implementation 
of demand-side measures. These measures are discussed at greater length 
below.
    As a preliminary matter, none of these situations, either alone or 
in combination, will necessarily lead to an electric reliability 
problem. There is excess generating capacity in the U.S. today and in 
most cases an EGU that closes, either temporarily until it comes into 
compliance or permanently, will not cause a reliability problem. As 
explained above, our modeling of the impact of this final rule at the 
regional level projects retirements of less than one percent of 
nationwide generating capacity and confirms that there will continue to 
be adequate capacity in all 32 subregions of the country as sources 
comply with the rule.\325\ This analysis shows that significantly less 
capacity will close in response to the final rule than might have under 
the proposal. Moreover, the regional modeling of retirements 
demonstrates that plants that close in response to this rule are spread 
out across the country rather than clustered in one area.
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    \325\ See Technical Support Document on Resource Adequacy in 
this Docket.
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    Outside analyses have identified many of the same flaws in studies

[[Page 9409]]

projecting large-scale retirements as a result of EPA's power sector 
rules. For example, on August 8, 2011, the Congressional Research 
Service (CRS) \326\ issued a report concluded that studies that assert 
that EPA rules will cause reliability problems, often make assumptions 
about the requirements of the rules that are inconsistent with, and 
dramatically more expensive than, the EPA's actual proposals. The CRS 
further noted that EPA's rules will primarily affect units that are 
more than 40-years old, that have not yet installed state-of-the-art 
pollution controls, and that are inefficient. Many of these plants are 
being replaced by combined cycle natural gas plants, driven more my 
lower gas prices than by EPA's regulations. The June 2011 Bipartisan 
Policy Center report referenced above likewise highlighted many of 
these same shortcomings in the studies in question.\327\
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    \326\ James E. McCarthy and Claudia Copeland, Congressional 
Research Service, August 8, 2011, ``EPA's Regulation of Coal-Fired 
Power: Is a `Train Wreck' Coming?''.
    \327\ Bipartisan Policy Center, June 2011, ``Environmental 
Regulation and Electric System Reliability.''
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    Although we do not expect to see any regional reliability problems, 
we acknowledge that there could be localized reliability issues in some 
areas--due to transmission constraints or location-specific ancillary 
services provided by retiring generation--if utilities and other 
entities with responsibility for maintaining electric reliability do 
not take actions to mitigate such issues in a timely fashion. There are 
many potential actions that could be taken to address this problem and 
multiple safeguards to assure a reliable electricity supply.
    First, utilities can help to assure reliability through proactive 
steps in coordination with relevant planning and regulatory 
authorities. As we said in the proposal, early planning is key. The 
industry has adequate resources to install the necessary controls and 
develop the new capacity that may be required within the compliance 
time provided for in the final rule.\328\ Although there are a 
significant number of controls that need to be installed across the 
industry, with proper planning, we believe that the compliance schedule 
established by the CAA can be met. Many companies have begun to do the 
detailed analysis and engineering and are ahead of others in their 
compliance strategy. There are already tools in place (such as 
integrated resource planning, and in some cases, forward auctions for 
future generating capacity) that ensure that companies adequately plan 
for, and markets are responsive to, future requirements such as this 
final rule.
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    \328\ As stated above, EPA has provided the maximum compliance 
time authorized under CAA section 112(i)(3)(A).
---------------------------------------------------------------------------

    Second, companies that intend to retire EGUs should formally notify 
their RTO (or comparable planning authority in the case of non-RTO 
regions), state regulatory agencies, and regional reliability entities 
as soon as possible of their compliance plans, particularly with regard 
to any planned unit retirements. As we said before, in most places a 
closing plant will not be a cause for concern for reliability. The same 
is true of any outages required for retrofitting of units with 
controls. To the extent there is concern, however, early notification 
will provide an opportunity for transmission planners, market 
participants, and state authorities to develop solutions to avoid a 
reliability problem. In RTOs with forward capacity markets, owner/
operators that do not bid generating capacity that they plan to shut 
down will provide an advance signal to market participants to take 
action to assure adequate future capacity. In all regions, early and 
public notification will allow market participants, planning 
coordinators and state authorities, as appropriate and in a timely 
fashion, to bring new generation on line, put demand side resources in 
place, and/or complete any transmission upgrades needed to circumvent a 
potential issue. Most RTOs only require 45 to 120 days notification of 
closure. In combined comments to EPA, 5 RTOs suggested that such 
notification should be made no later than 12 months after this 
regulation is final in order to allow a smooth transitioning to action 
to avoid a reliability problem. The EPA strongly encourages sources to 
provide notice to the RTOs as early as possible and believes that 
responsible owner/operators should and will do the early planning for 
compliance and provide early notification of their compliance plans, 
especially where such plans include retiring one or more units.
    On the supply side, there are a range of options including the 
development of more centralized power resources (either base-load or 
peaking) and/or the development of cogeneration or distributed 
generation. Even with the current large reserve margins, there are 
companies ready to implement supply-side projects quickly. For 
instance, in the PJM region, there are over 11,600 MW of capacity that 
have completed feasibility and impact studies; the units representing 
this capacity could be on-line by the third quarter of 2014.\329\ The 
EPA notes, as well, that in the 3 years from 2001 to 2003, industry 
brought over 160 GW of generation on line.\330\
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    \329\ Paul M Sotkiewicz, PJM Interconnection, Presentation at 
the Bipartisan Policy Commission Workshop Series on Environmental 
Regulation and Electric System Reliability, Workshop 3: Local, 
State, Regional and Federal Solutions, January 19, 2011, Washington, 
DC, http://www.bipartisanpolicy.org/sites/default/files/Paul%20Sotkiewicz-%20Panel%202_0.pdf, slide 6.
    \330\ Form EIA-860 Annual Electric Generator Report, http://www.eia.gov/cneaf/electricity/page/eia860.html.
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    Demand side options include energy efficiency as well as demand 
response programs. These types of resources can also be developed very 
quickly. In 2006, PJM had less than 2,000 MWs of capacity in demand 
side resources. Within 4 years this capacity nearly quadrupled to 
almost 8,000 MW of capacity.\331\ In addition to helping address 
reliability concerns, reducing demand through mechanisms such as energy 
efficiency and demand side management practices has many other 
benefits. It can reduce the cost of compliance and has collateral air 
quality benefits by reducing emissions in periods where there are peak 
air quality concerns.
---------------------------------------------------------------------------

    \331\ BPC slides cited above--slide 5.
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    With regard to transmission, recent experience also shows that, in 
many cases, transmission upgrades to address reliability issues from 
plant closures can be implemented in less than 3 years. For instance, 
when Exelon notified PJM of its intention to retire four units,\332\ it 
was determined that transmission upgrades necessary to allow retirement 
of two units could be made within 6 months of notification, 
transmission upgrades for the third unit would require slightly over 1 
year and transmission upgrades to allow the fourth unit to retire could 
be made in approximately 18 months.\333\
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    \332\ http://www.exeloncorp.com/Newsroom/pages/pr_20091202_Generation.aspx?k=eddystone.
    \333\ Cromby Units 1 and 2 and Eddystone Units 1 and 2--
Deactivation Study, Updated September 7, 2010--http://policyintegrity.org/documents/20100907-cromby-and-eddystone-retirement-study-posting-update.pdf.
---------------------------------------------------------------------------

    The CAA allows CAA Title V permitting authorities the discretion to 
grant extensions to the compliance time of up to one year if needed for 
installation of controls. See CAA section 112(i)(3)(B)). If an existing 
source is unable, despite best efforts, to comply within 3 years, a 
permitting authority has the discretion to grant such a source up to a 
1-year extension, on a case-by-case basis, if such additional time is 
necessary for the installation of controls. Id. Permitting authorities 
should be familiar with the operation of the 1-year

[[Page 9410]]

extension provision because EPA has established regulations to 
implement the provision and the provision applies to all NESHAP. See 40 
CFR 63.6(i)(4)(A).
    We believe that the permitting authorities have the discretion to 
use this extension authority to address a range of situations in which 
installation schedules may take more than 3 years including: staggering 
installations for reliability reasons or other site-specific challenges 
that may arise related to source-specific construction, permitting, or 
labor, procurement or resource challenges. Staggered installation 
allows companies to schedule outages at multiple units so that reliable 
power can be provided during these outage periods. It can also be 
helpful for particularly complex retrofits (e.g., when controls for one 
unit need to be located in an open area needed to construct controls on 
another unit). The additional 1-year extension would provide an 
additional two shoulder periods (i.e., seasons flanking annual high-
demand periods) to schedule outages, thus enabling owners/operators to 
gain the full benefit of staggering outages in support of complex 
installations. The EPA believes that although most units will be able 
to fully comply within 3 years, the fourth year that permitting 
authorities are allowed to grant for installation of controls is an 
important flexibility that will address situations where an extra year 
is necessary. That fourth year should be broadly available to enable a 
facility owner to install controls within 4 years if the 3-year time 
frame is inadequate for completing the installation.
    As we indicated at proposal, this source category is unique due to 
the large, complex and interconnected nature of electrical generation, 
transmission and distribution, and the critical role of the electric 
grid in the functioning of all aspects of the economy. The grid 
functions as an interconnected system that supplies electricity to end 
users on a continuous basis. Safe, reliable operation of the grid 
requires coordination among actions taken at individual units, 
including timing of outages for the installation of controls, derating, 
or deactivation. It was for this reason that we specifically addressed 
in the proposed rule reasonable interpretations of the phrase 
``installation of controls'' in CAA section 112(i)(3)(B). We determined 
that it was important to provide Title V permit authorities with 
information that might be useful if they were asked to authorize a 
fourth year for specific EGUs.
    The EPA took comment on whether the construction of on-site 
replacement power could be considered the ``installation of controls'' 
such that a fourth year would be available while the replacement unit 
is being completed for a unit that is retiring (e.g., a case when a 
coal-fueled unit is being shut down and the capacity is being replaced 
on-site by another cleaner unit such as a combined cycle or simple 
cycle gas turbine). After reviewing the comments, EPA believes that it 
is reasonable for permit authorities to allow the fourth year extension 
to apply to the installation of replacement power at the site of the 
facility. The EPA believes that building replacement power constitutes 
the ``installation of controls'' at a facility to meet the regulatory 
requirements.
    Commenters were generally supportive of the proposed approach 
described above, but a number of commenters suggested several 
additional situations that should be considered as the ``installation 
of controls'' such that it would be appropriate for permitting 
authorities to grant a 1-year extension beyond the 3-year compliance 
time-frame. In particular, commenters suggested that the 1-year 
extension should be available for a unit if a company's compliance 
choice was to retire that unit but doing so within the 3-year time-
frame caused reliability problems for any of the following reasons: (1) 
Generation from the retiring unit is needed to maintain reliability 
while other units install emission controls; (2) new off-site 
generation was being built to replace the retiring unit, but the new 
generation was not scheduled to be operational within the 3-year time-
frame and any gap between the time the existing unit retires and the 
new unit comes on line would cause reliability problems; and (3) 
transmission upgrades were needed in order to maintain electric 
reliability after the unit retired but could not be completed within 3 
years.
    While the ultimate discretion to provide a 1-year extension lies 
with the permitting authority, EPA believes that all three of these 
cases may provide reasonable justification for granting the 1-year 
extension if the permitting authority determines, for example, based on 
information from the RTO or other planning authority or other entities 
with relevant expertise, that continued operation of a particular unit 
slated for retirement for some or all of the additional year is 
necessary to avoid a serious risk to electric reliability.
    In a case where pollution controls are being installed, or onsite 
replacement power is being constructed to allow for retirement of 
older, under-controlled generation, a determination that an extra year 
is necessary for compliance should be relatively straightforward. In 
order to install controls, companies will have to go through a number 
of steps fairly early in the process including obtaining necessary 
building and environmental permits and hiring contractors to perform 
the construction of the emission controls or replacement power. This 
should provide sufficient information for a permitting authority to 
determine that emission controls are being installed or that 
replacement power is being constructed. Because companies will need to 
develop this information early in the process and because a 
determination can easily be made as to whether the schedule will exceed 
3 years, the EPA believes that Title V permitting authorities should be 
able to quickly make determinations as to when extensions are 
appropriate.
    In the three cases related to retirement of a unit without 
construction of onsite replacement power, additional information is 
needed. The Title V permitting authority should request that the 
affected company or companies provide information, including, for 
example, from the RTO or other planning authority for the relevant 
region, the state electric regulatory agency, NERC or its regional 
entities, and/or FERC or the DOE, demonstrating that retirement of a 
particular unit within the 3-year compliance period would result in a 
serious risk to electric reliability.
    The first two situations involving a retiring unit--where one or 
more related existing units are upgrading pollution controls or a new 
unit is being constructed off-site--are similar to the situation we 
discussed in the proposed rule wherein a retiring unit at a facility 
runs an additional year while a replacement unit on the same site is 
constructed. In each of these situations, the retiring unit would be 
allowed to run so a unit compliant with the rule (either a retrofitted 
existing unit or a new unit) can come on line. We believe that these 
situations may, in the appropriate circumstances, constitute ones in 
which a 1-year extension for the retiring unit is ``necessary for the 
installation of controls.'' In these two situations, however, we 
believe that it would be appropriate for the Title V permitting 
authority to consider reliability concerns as a necessary factor before 
granting the additional year because continuing operation of the 
retiring unit is only ``necessary'' to the extent it is required for 
reliability. In each of these situations, the permitting authority 
should determine that the retiring unit is necessary to maintain

[[Page 9411]]

reliability until the new unit comes on line or the other existing unit 
is retrofitted. Title V permitting authorities may determine that 
multiple retiring units are available to maintain reliability, but 
unless all the units are necessary to address the issue, it would 
likely be unreasonable to provide the additional year for all the 
identified units.
    The third hypothetical situation identified above is one in which 
transmission upgrades are necessary to address a reliability issue 
resulting from the retirement of a unit in order to comply with this 
rule, where the upgrade cannot be completed by the 3-year compliance 
date. In terms of the functionality of the electric grid, this 
situation has some similarity to those discussed above. Here, it is the 
completion of the transmission upgrades, rather than bringing another 
compliant (retrofitted or new) unit on line, that would allow the 
retiring unit to come into compliance (by retiring) without threatening 
reliability. The general objective and result is similar: Reductions of 
the existing unit's HAP emissions (through retirement) while 
maintaining electric reliability. If such situations develop and the 
reliability problem has been properly demonstrated, permitting 
authorities should consider whether an extension under CAA section 
112(i)(3)(B) may be provided.
    The EPA continues to believe, based on the analysis discussed at 
the beginning of this section, that most, if not all, units will be 
able to comply with the requirements of this rule within 3 years. The 
EPA also believes that making it clear that permitting authorities have 
the authority to grant a 1-year compliance extension where necessary, 
in the range of situations described above, addresses many of the other 
concerns that commenters have raised. The EPA believes that the number 
of cases in which a unit is reliability critical and in which it is not 
possible to either install controls on the unit or mitigate the 
reliability issue through construction of new generation, transmission 
upgrades, or demand-side measures, within 4 years, is likely to be very 
small or nonexistent. This view is consistent with statements from 
commenters explicitly mandated with ensuring grid reliability.
    The EPA's authority to provide relief from the requirements of this 
final rule beyond the fourth year is limited by the statute. If 
reliability issues do develop, however, the CAA provides mechanisms for 
sources to come into compliance while maintaining electric reliability. 
One area where the EPA has some measure of flexibility is with respect 
to the exercise of its enforcement authorities. The Agency has used 
such authority in the past to bring sources into compliance with the 
requirements of the CAA while maintaining electric reliability, 
although these authorities are not as flexible as suggested by some 
commenters.
    The EPA generally does not speak publicly to the intended scope of 
its enforcement efforts, particularly well in advance of the date when 
a violation may occur. In light of the importance of ensuring electric 
reliability, however, the Office of Enforcement and Compliance 
Assurance will separately publish a document that articulates our 
intended approach with respect to sources that operate in noncompliance 
with this final rule to address a specific and documented reliability 
concerns.
    That document provides a pathway for reliability critical units (as 
such units are described in the document) to achieve compliance within 
an additional year. The result is that qualifying reliability critical 
units may come into compliance within up to 5 years. This pathway is 
structured to maintain reliability, to ensure CAA compliance and to 
increase certainty for sources in planning by allowing a unit owner/
operator to determine whether it qualifies for a compliance schedule 
well in advance of the MATS compliance deadline.
    The EPA believes that there will be few, if any, situations in 
which it will be necessary to have recourse to the processes discussed 
in the document just described, and that there are likely to be fewer, 
if any, cases in which it is not possible to mitigate a reliability 
issue within the further year contemplated under that document. 
However, there is always the possibility that some unit owner/operator 
will be unable to address its reliability issues within 5 years and 
there is always the possibility that a unit owner/operator will be 
unable to timely comply with the MATS for some other reason. Consistent 
with its longstanding historical practice under the CAA, the EPA will 
address individual non-compliance circumstances on a case-by-case 
basis, at the appropriate time, to determine the appropriate response 
and resolution.
    A number of commenters also raised concerns about inconsistencies 
between the compliance timelines under this final rule and existing 
state agreements with specific owners/operators to install pollution 
control equipment and/or retire EGUs. The EPA believes the 
flexibilities provided in this discussion allow for some discretion to 
address those cases, but that they may not be fully addressed. The EPA 
is supportive of such efforts and believes they can have important 
multi-pollutant health and environmental benefits. To the extent that 
the flexibilities discussed here do not fully address a particular 
situation, we encourage states and sources to contact the EPA as early 
as possible to discuss their individual circumstances.

G. Cost and Technology Basis Issues

1. Dry Sorbent Injection
    Comment: Several commenters stated that there is limited commercial 
operating experience in using DSI to control acid gas emissions from 
coal-fired boilers. They suggest that the technology is not adequately 
proven for use in this application.
    Other commenters disagree with statements made that DSI is not 
proven. One commenter stated that DSI is a mature technology. The 
commenter indicated that DSI is well suited for units that burn fuels 
with lower or mid-level sulfur contents, and is among the viable 
options available for a number of sources to achieve the proposed HCl 
limits. Thus, the commenter believes that DSI represents a real 
technology control option for many units, and is among the suite of 
technology options that certain units will be able to employ to meet 
the proposed HCl limit.
    Response: As explained in this response and elsewhere in this 
preamble, the EPA agrees that DSI technology is proven and ready for 
commercial use in controlling acid gases from coal combustion. One of 
the largest coal-burning electric utilities in the U.S, American 
Electric Power (AEP), pioneered the practical use of DSI with trona, a 
sodium-based sorbent, for SO3 mitigation. American Electric 
Power has implemented trona injection for that purpose across its 
entire bituminous coal-fired fleet where both SCR and wet FGD systems 
are in place.\334\ Examples of coal-fired EGUs already using trona DSI 
to control SO2 emissions include NRG Energy's Dunkirk 
Generating Station Units 1-4 and CR Huntley Units 67 and 68 in New 
York.\335\ The Dunkirk units range in size from 75 MW to 190 MW. Much 
larger units may also be economic when using DSI for SO2 
control, as suggested by Dominion Energy's studies of adding DSI on two

[[Page 9412]]

625 MW units at the Kincaid plant in Illinois.\336\ One of the largest 
suppliers of air emission control systems in the world, vouches that 
DSI is commercially proven for acid gas control:337 338
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    \334\ SO3 Control: AEP Pioneers and Refines Trona Injection 
Process for SO3 Mitigation, Coal Power, March 2007, http://www.coalpowermag.com/plant_design/SO3-Control-AEP-Pioneers-and-Refines-Trona-Injection-Process-for-SO3-Mitigation_29.html.
    \335\ NRG Energy letter to RGGI, Inc, November 22, 2010, http://www.rggi.org/docs/NRG_Nov_2010.pdf.
    \336\ Dominion Energy, BART Analysis for the Kincaid Power 
Plant, January 2009, http://www.epa.state.il.us/air/drafts/regional-haze/bart-kincaid.pdf.
    \337\ Dry Sorbent Injection Systems for Acid Gas Control, 
Babcock & Wilcox, 2010, http://www.babcock.com/library/pdf/ps-451.pdf.
    \338\ Technologies for Acid Gas Control, Babcck & Wilcox, 2011, 
http://www.babcock.com/library/pdf/ps-457.pdf.
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    Comment: Numerous comments were received on EPA's IPM modeling of 
DSI in the MATS analysis. A few commenters stated that DSI will not 
work on bituminous coals. Some commenters stated that DSI is only 
suitable for use on low sulfur, low chlorine western coals. Others 
stated that DSI is only likely to be used on relatively small units, 
and that larger units would use scrubbers for acid gas control. Several 
commenters expressed the opinion that because there is little 
commercial operating experience in using DSI to control SO2 
emissions from coal-fired boilers, EPA's IPM modeling assumptions on 
the efficacy and cost of the DSI control option are unjustifiably 
optimistic. Some commenters believe that DSI will not be as economic or 
as widely applicable for either SO2 or HCl control as 
projected by EPA's IPM modeling. Commenters observe that wet or dry 
scrubbers for FGD, longer-standing control technologies for 
SO2 and HCl, are more complex systems with a much higher 
capital cost than DSI. These commenters argue that the sector will need 
to retrofit many more FGD scrubbers than projected by IPM for MATS 
compliance and will therefore experience a much higher overall cost of 
compliance than projected by IPM, as well as needing more time and 
resources for retrofit construction. A few commenters suggested that 
EPA should base its MATS modeling on this more conservative outlook. A 
few commenters were concerned that EPA's DSI modeling assumptions 
relied on performance data from only one DSI vendor.
    Some commenters were concerned that fly ash currently sold for 
beneficial uses will become unsalable because it will be contaminated 
by injected sodium-based DSI sorbents. Two commenters argued that EPA's 
IPM analysis understates DSI cost by not including the costs of 
foregone fly ash sales revenue and contaminated fly ash disposal. A few 
commenters observed that landfilling of sodium-based DSI solid wastes 
will produce leachate containing sodium and other compounds that are 
challenging to handle, thus requiring special landfill designs and a 
high cost for landfill disposal of DSI waste.
    Response: The EPA believes that its representation of DSI in MATS 
compliance modeling is reasonable, is properly limited to applications 
that are technically feasible, and reflects a conservative approach to 
modeling future use of this technology.
    The EPA disagrees that its IPM modeling of DSI is overly optimistic 
and therefore underestimates the costs of MATS compliance. In its IPM 
modeling, EPA restricts the availability of the DSI option to only 
those units that use or switch to relatively low sulfur coal: Less than 
2 lb SO2/MMBtu (see IPM documentation in the docket). The 
EPA's IPM projections for MATS compliance, therefore, already include 
the costs of any additional FGD scrubbers that are economically 
justified and projected for use on units using higher sulfur coals. The 
EPA models DSI assuming fine-milled trona as the injected sorbent. As 
mentioned by several commenters, sodium bicarbonate (SBC), which is 
processed from trona, is also suitable for use with DSI. Sodium 
bicarbonate is more reactive with acid gases than trona. It would 
require less tonnage of sorbent and less tonnage of waste disposal than 
trona for the same SO2 removal effect, albeit at somewhat 
higher sorbent cost. Non-sodium based sorbents such as hydrated lime 
(calcium based) could also be used. Therefore, EPA's modeling of DSI 
technology does not include the full spectrum of sorbent choices that 
real-world applications enjoy, meaning that there may be opportunities 
for lower-cost applications of DSI that are not captured in EPA's 
projections for MATS. The EPA models DSI with trona injection rates 
corresponding to 70 percent SO2 removal for all coals, 
assuming that an equivalent amount of sorbent is needed to provide 90 
percent HCl removal, regardless of the low sulfur and chlorine content 
of western coals.
    Senior technical staff from the EPA have carefully evaluated the 
key assumptions regarding the cost and operation of emission control 
technologies. In general, these staff believe that trona should have 
strong HCl reaction selectivity and, consequently, EPA's assumed trona 
injection rates may be overstated. The extent to which this assumption 
may actually overstate DSI control costs can be observed through DSI 
pilot testing for Solvay Chemicals by the Energy & Environmental 
Research Center (EERC) at the University of North Dakota.\339\ The 
EERC's testing of trona DSI on a central Appalachian bituminous coal 
(1.3 lb SO2/MMBtu) substantiates the strong HCl reaction 
selectivity of sodium-based sorbents, including trona, and calcium-
based hydrated lime. The EERC's pilot testing shows that fine-milled 
trona, when well mixed into 325 [deg]F flue gas upstream of a FF, 
provides 90 percent HCl removal at a SO2 removal rate of 
less than 20 percent (as compared to EPA's modeling assumption of 
aligning 90 percent HCl removal with sorbent injection designed to 
achieve 70 percent SO2 removal). The data show that 95 
percent or higher HCl removal is readily obtained at somewhat higher 
SO2 removal rates. Similarly strong HCl selectivity results 
were obtained using trona and an ESP at 650 [deg]F. Test data from 
United Conveyor \340\ on full-scale units also show these high HCl 
selectivity trends. Overall, these test data from multiple major 
vendors suggest that even if a SO2 removal rate of 30 
percent were required in order to obtain 90 percent HCl removal in the 
imperfectly mixed flow of a full-scale unit, it still appears that 
EPA's assumed trona injection rates may be as much as twice as high as 
would actually be needed in practice for certain applications. It is 
apparent that if EPA were to re-analyze MATS compliance with DSI 
injection rates reduced by 50 percent, there would be a corresponding 
reduction in the sorbent and related waste disposal costs that 
constitute most of the cost of using DSI.
---------------------------------------------------------------------------

    \339\ Solvay Chemicals, Inc., HCl Removal in the Presence of 
SO2 Using Dry Sodium Sorbent Injection, http://www.solvair.us/SiteCollectionDocuments/presentations/20111214_hcl_presentation.pdf.
    \340\ United Conveyor Corporation, Dry Sorbent Injection for 
Simultaneous SO2, HCl, and Hg Removal, October 2011, http://unitedconveyor.com/uploadedFiles/Systems/Systems_Sub/McIlvaine%20Multipollutant%20Removal%20Oct%202011.pdf.
---------------------------------------------------------------------------

    Given the EERC test data, it is also apparent that most units that 
have ESPs and are burning low sulfur western coal could meet the HCl 
limit using DSI without the addition of a FF. If EPA were to re-analyze 
MATS compliance while allowing DSI use without the need for a 
downstream FF, it is apparent that there would be a very significant 
reduction in the overall number of FF retrofits projected, and a 
corresponding reduction in annualized capital costs. For the MATS 
proposal, the EPA modeled DSI on the assumption that all chlorine in 
coal converts to HCl, and that DSI would be the only mechanism by which 
the unit could prevent HCl from being emitted. Based on public

[[Page 9413]]

comments and a more thorough review of the ICR data, the EPA has 
introduced in final MATS modeling a recognition that the relatively 
high alkalinity of ash from subbituminous and lignite coals ``removes'' 
much of the HCl that would otherwise be emitted from combustion of 
these particular coals. The 2010 ICR data indicate that in some cases 
the ash itself removes sufficient HCl from these coals for MATS 
compliance; in effect, these acid-gas emissions are absorbed by coal 
ash and are captured by particulate control devices instead of being 
emitted in gaseous form. As a conservative measure, EPA's revised final 
MATS modeling assumes that 75 percent of HCl is removed by the ash for 
these coals. In the event that ash capture in practice is more 
effective than this 75 percent assumption, then EPA's analysis projects 
a conservatively higher level of DSI installations (and, thus, 
compliance cost) than would actually occur in practice. In any case, it 
appears that significantly less sorbent injection would actually be 
required in practice than assumed by EPA for these low sulfur, low 
chlorine coals, and that the IPM projected DSI operating costs are 
likewise higher for these coals than would be experienced in practice.
    The EPA models DSI with sorbent injection occurring downstream of 
an existing electrostatic precipitator (ESP). The existing ESP is 
assumed to remain in service. The model adds a fabric filter downstream 
of the DSI injection point to capture the small amount of PM passing 
through the ESP plus the reacted and unreacted DSI sorbent. Most of the 
DSI projected by IPM, therefore, includes the costs of a retrofitted 
FF. This modeled configuration allows fly ash currently captured in 
ESPs to remain uncontaminated by DSI sorbent and, therefore, remain 
available for sale and beneficial use. The EPA conservatively models FF 
costs based on an assumed full-size system with an air-to-cloth ratio 
of 4.0. The FF costs could be somewhat less in practice if a smaller 
system (with an air-to-cloth ratio of 6.0) were used for the reduced 
DSI dust loading. The EPA observes that some of the owners of units 
with ESPs may chose to convert existing ESPs into FFs,\341\ an option 
not modeled in IPM, but that would likely have a lower capital cost 
than a retrofitted FF. In the MATS proposal EPA modeled DSI with a 
waste disposal cost of $50/ton, based on a Sargent & Lundy DSI cost 
model prepared for EPA (see proposal IPM documentation in the docket). 
The EPA has continued to model DSI at this waste disposal cost for 
analysis of the final rule. However, recent discussions between senior 
technical staff from the DOE and the EPA have suggested that in some 
situations sodium sulfates, that would be formed by the injection of 
trona, could potentially leach out of the fly ash/sorbent mixture on 
contact with water. Although the technical staff recognized that these 
concerns are more relevant to bituminous coal-fired units where ashes 
are not cementitious, unless mixed with limestone or lime, they 
suggested that the impacts of potentially higher disposal costs be 
evaluated. Based on public comments, further investigations by Sargent 
& Lundy, and suggestions from the EPA and DOE technical staff, EPA's 
analysis of the final rule has included an IPM sensitivity case using a 
DSI waste disposal cost of $100/ton. The sensitivity case indicates 
that a 100 percent increase in assumed DSI waste disposal cost produces 
slightly less than a 1 percent increase in the projected cost of the 
rule.
---------------------------------------------------------------------------

    \341\ TW Lugar, et al., The Ultimate ESP Rebuild: Casing 
Conversion To a Pulse Jet Fabric Filter, a Case Study, Electric 
Power Conference, May 2009, http://www.cecoenviro.com/uploads/ESP%20to%20Fabric%20Filter%20Baghouse%20Conversion%20-%20Buell%20Case%20History.pdf.
---------------------------------------------------------------------------

    Comment: A few commenters expressed the concern that there is an 
inadequate supply of trona to support DSI operations at the levels 
projected by the EPA for MATS compliance.
    Response: The EPA projects that just over 50 GW of coal-fired 
capacity might retrofit with DSI for MATS compliance, thus reducing 
SO2 emissions by about 1 million tons per year. Based on 
conservatively high trona injection rates, as discussed above, the EPA 
estimates that the amount of trona required to support DSI operations 
at this level is about 4 million tons per year. By comparison, the 
trona mining industry in the U.S. has a demonstrated production 
capacity of at least 18 million tons annually, and was running well 
below that capacity (16.5 million tons) in 2010.342 343 If 
the EPA's assumed trona injection rates are as much as 50 percent 
greater than actually needed for at least 90 percent HCl control, as 
discussed above, and given that some subbituminous coals will 
apparently need little or no sorbent injection for HCl control, there 
may already be an adequate surplus of trona production capacity to 
support DSI for MATS compliance. The EPA, therefore, concludes that 
trona supply for DSI is either already adequate, or will require at 
most a small increase in production capacity.
---------------------------------------------------------------------------

    \342\ http://www.wma-minelife.com/trona/tronmine/tronmine.htm.
    \343\ http://www.wma-minelife.com/trona/TronaPage2/trona_production.htm.
---------------------------------------------------------------------------

    For all of these reasons, the EPA believes that its representation 
of DSI in MATS compliance modeling is reasonable, is properly limited 
to applications that are technically feasible, and reflects a 
conservative approach to modeling future use of this technology.
2. Economic Hardship
a. Job Losses and Economic Impacts
    Comment: Several commenters indicated that they believe the 
proposed rule will weaken industry, cause job losses and hurt power 
consumers. One commenter reported that the proposed rule will affect 
1,350 coal and oil-fired units at 525 power plants and that NERC 
reports that by 2018 nearly 50,000 MW of capacity will be retired by 
the proposed rule. Many of these commenters compared the cost estimated 
by EPA to a variety of other sources that estimate substantially higher 
costs of the rule. The commenters expressed concern that electricity 
price increases are likely to be up to 24 percent in some regions as a 
result of the proposed rule. In addition to the economic difficulty the 
proposed rule could place on consumers, the commenter believes that 
many in the energy sector will lose their jobs due to coal-fired 
capacity losses. The commenters believe the effects on coal-fired 
plants in the Southeast especially will mean the loss of high-paying, 
high-skilled jobs and drastic price increases in energy costs. 
Additionally, commenters expressed concern that increased electricity 
and natural gas prices would impact businesses in multiple sectors 
across the country.
    Response: The EPA disagrees with the estimates presented by the 
commenters. The EPA has updated its analysis to reflect the final MATS. 
The Agency estimates the annual costs of the final rule in 2015 to be 
$9.6 billion in 2007 dollars. The estimate of early retirements of 
coal-fired units due to this rule is 4.7 GW, lower than the level 
estimated at proposal. Both of these estimates were prepared using the 
IPM, a model that has been extensively reviewed and has been utilized 
in several rulemakings affecting the power generation sector over the 
last 15 years. The Agency's analyses are credible and accurate to the 
extent possible, and all assumptions and data are made public. 
Limitations and caveats to these analyses can be found in the RIA for 
this rule.
    The EPA estimates that there will be an increase of 3.1 percent in 
retail

[[Page 9414]]

electricity price on average in the contiguous U.S. in 2015 as an 
outcome of this rule, with the range of increases from 1.3 percent to 
6.3 percent in regions throughout the U.S. No region of the U.S. is 
expected to experience a double-digit increase in retail electricity 
prices in 2015 or in any year later than that, according to the 
Agency's analysis, as a result of this rule. To put this in context, 
the roughly 3 percent incremental increase in aggregate end-user 
electricity prices projected to occur over the next 4 years is about 
the same as the 3 percent absolute average change in total end-user 
electricity prices observed on an annual basis.\344\ Furthermore, the 
roughly 3 percent incremental price effect of this rule is small 
relative to the changes observed in the absolute levels of electricity 
prices over the last 50 years, which have ranged from as much as 23 
percent lower (in 1969) to as much as 23 percent higher (in 1982) than 
prices observed in 2010.\345\ Even with this rule in effect, 
electricity prices are projected to be lower in 2015 and 2020 than they 
were in 2010.\346\
---------------------------------------------------------------------------

    \344\ EIA Annual Energy Outlook 2010 annual total electricity 
prices from 1960 to 2010, Table 8-10.
    \345\ Ibid, EIA AEO 2010, Table 8-10.
    \346\ Ibid, EIA AEO 2010, Table 8-10 for price levels; and 
Chapter 3 of the RIA for electricity price differential.
---------------------------------------------------------------------------

    The Agency found that the readily discernible impact on long-term 
employment nationally within the most directly affected sectors should 
be small and the EPA also estimated that about 46,000 job-years \347\ 
of one-time construction labor could be supported or created by this 
rule. This includes jobs manufacturing steel, cement and other 
materials needed to build pollution control equipment, jobs creating 
and assembling pollution control equipment, and jobs installing the 
equipment at power plants. Potential job increases from increased 
output by lower-emitting facilities (such as increased generation from 
well-controlled coal-fired plants that replace generation from older 
coal-fired plants) are expected to partially or fully offset potential 
job losses resulting from reduced output from higher-emitting 
facilities. The EPA analysis projects a net change in the directly 
affected EGU sector of between 15,000 net jobs lost to 30,000 net jobs 
gained on an annual basis.\348\ See Chapter 6 of the RIA for further 
details.
---------------------------------------------------------------------------

    \347\ A ``job-year'' is a combined measure of jobs and job 
duration which is equivalent to one person being employed for one 
year. For example, 2 job-years could represent two years of 
employment for one worker, one year of employment for two workers, 
or 6 months of employment for four workers. Estimates of employment 
changes that involve non-permanent workers are usually reported in 
job years to give a sense of the total employment effects.
    \348\ It should be noted that if more labor must be used to 
produce a given amount of output, then this implies a decrease in 
labor productivity. A decrease in labor productivity will cause a 
short-run aggregate supply curve to shift to the left, and 
businesses will produce less, all other things being equal.
---------------------------------------------------------------------------

    The EPA has also looked at the possibility that changes in the 
price of electricity may influence the levels and geographic 
distribution of downstream economic activities, and associated 
employment. Projecting how potentially higher electricity prices may 
affect various downstream economic activities in particular regions as 
a result of this rule is challenging for several reasons: (1) There are 
significant uncertainties regarding projections of consumer- and 
location-specific electricity price changes in response to future firm-
specific compliance strategies; (2) the availability of competitively-
priced alternative energy sources (including energy conservation) and 
less electricity-intensive substitute goods and services may 
significantly mitigate potentially adverse economic consequences 
resulting from projected increases in electricity prices in ways which 
are not captured effectively in currently available models; and (3) 
available modeling tools are not configured to capture the effects over 
time of economically significant effects of cleaner air (e.g., 
reductions in medical expenditures and improvements in labor 
productivity resulting from fewer lost work days) achieved by rules 
evaluated using single target year criteria pollutant and/or HAP 
benefits projections. After considering these methodological 
limitations, the Agency concludes that there is not a satisfactory 
methodology for projecting the downstream economic (including 
employment) effects of any changes in electricity prices due to this 
rule.
    We expect the downstream economic effects of this rule to be small 
because electricity is only a small factor in the production of most 
goods and services.\349\ A 3 percent increase in end-user electricity 
prices translates to a much smaller effect on prices and potential 
output of goods and services from end-users of electricity. Over time, 
the incremental effect of this rule on electricity prices is projected 
to diminish significantly; for example the difference in expected 
prices is projected to narrow from 3.1 percent in 2015 to 2.0 percent 
in 2020 as shown in Chapter 3 of the RIA.
---------------------------------------------------------------------------

    \349\ BEA. (2007b). Commodity-by-Industry Direct Requirements 
after Redefinitions, 2002. Available in: 2002 Summary Tables, 2002 
Benchmark Input-Output Data. Retrieved from http://www.bea.gov/industry/io_benchmark.htm#2002data.
---------------------------------------------------------------------------

    Despite the absence of a satisfactory methodology for quantifying 
the potential economy-wide effects (including employment) of any 
potential increases in electricity prices resulting from this rule, the 
EPA expects the incremental effects of this rule on electricity prices 
to be small given the projected electricity price increases relative to 
historical levels and volatility in end-user electricity prices. Based 
on these projections and contextual information, the Agency believes 
that the incremental effects on electricity prices and economic 
activity of this rule are likely to be small relative to other factors 
influencing electricity prices, overall employment, and other aspects 
of economic activity.
    Comment: Several commenters considered the proposed rule to be a 
tax on the American public, since utilities implementing upgrades will 
pass the costs on to the consumer. Commenters questioned the preference 
of Americans to subsidize renewable energy sources and put money into 
the proposed rule instead of other environmental programs with greater 
benefits. Commenters explained that the tax-like price increase reduces 
income of energy consumers and depresses business development. The 
commenters used California as an example of a state that uses low rates 
of coal-based electricity and cites companies that have left the state 
as a result of substituting higher cost forms of electricity for coal. 
A commenter stated that coal-derived energy will rapidly become more 
expensive, especially in the ``rust belt'' and Southeast region, as can 
be seen by the rate increase already requested in Louisville. A 
commenter believes the ``indirect taxation'' limits the ability of the 
economy to absorb the cost of retrofitting and new capacity projects, 
lowers discretionary spending and leads to job losses and lost tax 
revenues, given the restrictive timeframe for compliance.
    Response: The Agency does not agree that this rule creates or 
alters any taxes on affected sources required under this rule to reduce 
their emissions of toxic air pollutants, nor are taxes created or 
altered or imposed on consumers of electricity which is provided to the 
market by affected sources. Moreover, unlike a tax, this rule does not 
generate government revenue. The rule does, however, indirectly address 
the problem of the ``externality cost'' of higher health risks and 
other adverse effects on the populations exposed to toxic air pollution 
emissions from affected sources. This rule may have the effect of

[[Page 9415]]

reducing or eliminating a market distortion that provides an implicit 
subsidy to affected facilities. This implicit subsidy results from the 
fact that some facilities currently can avoid the costs of toxic air 
pollution controls by imposing higher health and other costs on those 
who are exposed to higher levels of toxic air pollution. The Agency 
also disagrees with the implication that the costs incurred by less-
controlled sources to bring their toxic air emissions in line with 
their better-controlled competitors will lead to significant or 
debilitating changes in market and economic conditions. The Agency's 
estimate of the potential increase in retail electricity price is an 
average of 3.1 percent in 2015, with a range of increases by region 
from 1.3 percent to 6.3 percent. As shown in Chapter 3 of the RIA, the 
higher rates of potential electricity price increase tend to occur in 
those regions where electricity prices have been relatively low, due to 
some extent to reliance on coal-fired units which have been cheaper to 
operate due to underinvestment in toxic air pollution controls.\350\ As 
shown in Chapter 3 of the RIA, all regions with year 2015 projected 
percentage increases in retail electricity prices above the contiguous 
U.S. average are also projected to have baseline retail electricity 
prices which are below the contiguous U.S. average price level in that 
year. In addition, natural gas prices will only increase by 0.3 to 0.6 
percent on average over the time horizon of 2015 to 2030. As discussed 
above, for consumers of electricity in the commercial and industrial 
sectors, electricity tends to be a fairly small fraction of total costs 
of production, implying that the average projected electricity price 
increase of 3 percent will lead to only a small fractional change in 
the costs of providing goods and services to the economy. While some 
residential electricity consumers may similarly see a small price 
increase in retail electricity prices, it should be noted that these 
consumers tend to reside in the same area or region as the affected 
facility and so will also experience the improvement in air quality 
from the reductions due to the rule. The reduction in health risk and 
other improvements to quality of life associated with lower exposure to 
toxic and other air pollutants achieved by this rule will confer 
benefits on these consumers which include lower risks of premature 
mortality, lower morbidity, and improved productivity and 
competitiveness of U.S. workers due to reduction in work days lost to 
air pollution-related illness. The benefits of these improvements are 
projected to exceed costs of compliance by affected sources by at least 
six-fold. The potential price increases in electricity and natural gas 
should be considered in light of the substantial health, welfare, and 
economic benefits achieved by this rule.
---------------------------------------------------------------------------

    \350\ http://www.epa.gov/airmarkets/images/CoalControls.pdf.
---------------------------------------------------------------------------

    Comment: Many commenters expressed support for the EPA's impact 
analysis and disputed claims by other commenters that the projected 
rule will harm economic growth. A number of commenters mentioned 
testimonials by power company CEOs stating that the proposed rule will 
not affect the economic health of the industry and a survey showing 
nearly 60 percent of the coal-fired units already comply with the EPA's 
proposed Hg standard, and several other meaningful quotes from utility 
executives. The commenters also pointed out that 17 states already 
require plants to address Hg pollution, with some imposing more 
stringent emission limits than the EPA proposes. The commenters believe 
that utilities use the threat of power plant closures and lost jobs to 
delay Hg reductions from coal-fired plants. Commenters also believe 
that the rules will drive innovation and job creation as new 
technologies to reduce pollution are created. Several commenters quoted 
the Economic Policy Institute finding that the proposed rule will 
increase job growth by 28,000 to 158,000 jobs by 2015 (including 
approximately 56,000 direct jobs and 35,000 indirect jobs), the 
University of Massachusetts study that showed an increase 1.4 million 
jobs in 5 years, and the Constellation Energy Group installation 
project that employed nearly 1,400 skilled workers. Commenters also 
cited the University of Massachusetts study statement that a net gain 
of over 4,200 long-term operation and maintenance jobs will result.
    Several commenters observed that the positive impacts of the rule 
strongly favor its adoption. These commenters stated that, contrary to 
the unfounded assertions by critics of EPA and the rule, EPA has 
conducted a technically sound and conservative benefit-cost analysis 
showing that the proposed rule's estimated benefits are at least five 
times as high as its costs. One commenter stated, ``With sound, albeit 
unduly conservative, econometric modeling, EPA has also determined that 
the Toxics Rule will promote economic growth and create jobs in both 
the long and short term.'' Two commenters cited the EPA impact analyses 
by Dr. Charles Cicchetti which confirm this finding and state that the 
analysis underestimates the rule's net benefits and positive impacts on 
the nation's economy. By considering some benefits not monetized in the 
EPA analysis, Dr. Cicchetti concludes that the proposed rule will 
create $52.5 to $139.5 billion in net benefits annually, create 115,200 
jobs, generate annual health savings of $4.513 billion, annual 
increases in GDP of $7.17 billion and $2.689 billion in additional 
annual tax revenues, and spur innovation and modernization of EGUs. The 
commenters state that the study findings show no need to delay 
implementation of the rule or needlessly duplicate economic analyses 
already completed.
    Commenters reported that multiple researchers confirmed that the 
EPA's estimates of economic stimulus are conservative and that the 
proposed rule will stimulate job growth. A commenter quotes Dr. Josh 
Bivens of the Economic Policy Institute, who also found that EPA's 
conclusions were conservative. Dr. Bivens concluded, ``The EPA RIA on 
the proposed toxics rule makes a compelling case that the rule passes 
any reasonable cost-benefit analysis with flying colors--the monetized 
benefits of longer lives, better health, and greater productivity dwarf 
the projected costs of compliance * * * Whether regulation in general 
and the toxics rule in particular costs jobs is an empirical question 
this paper attempts to answer. In particular, this paper examines the 
possible channels through which the proposed toxics rule could affect 
employment in the United States and finds that claims that this 
regulation destroys jobs are flat wrong: ``The jobs-impact of the rule 
will be modest, but it will be positive.'' His report details the 
following major findings:
    1. The proposed rule would have a modest positive net impact on 
overall employment, likely leading to the creation of 28,000 to 158,000 
jobs between now and 2015.
    2. The employment effect of the [MATS] on the utility industry 
itself could range from 17,000 jobs lost to 35,000 jobs gained.
    3. The proposed rule would create between 81,000 and 101,000 jobs 
in the pollution abatement and control industry (which includes 
suppliers such as steelmakers).
    4. Between 31,000 and 46,000 jobs would be lost due to higher 
energy prices leading to reductions in output.
    5. Assuming a re-spending multiplier of 0.5, and since the net 
impact of the above impacts is positive, another 9,000 to 53,000 jobs 
would be created through re-spending.

[[Page 9416]]

    Response: The EPA thanks the commenters for these observations. The 
Agency's estimates of employment impacts, found in the RIA for the 
rule, are smaller than those identified by the some commenters, though 
the EPA uses a different methodology that focuses on impacts specific 
to the electric power sector.
b. Impacts on Low-Income Consumers
    Comment: Commenters expressed concern that the EPA's overview of 
the price increases does not consider the hardships that will be the 
reality of increased prices on low-income or fixed-income households or 
small businesses. The commenter reports increases of $90 million in 
capital costs, $11.4 million in annual operating costs and $6.4 million 
in annual debt service costs to achieve compliance, which will lead to 
a 13 percent increase in rates for the proposed rule, and a 41 percent 
increase for all proposed and new regulation compliance costs. The 
commenter argues against the EPA's view that energy efficiencies will 
offset rate increases, because low income customers will need to use 
less electricity due to economic necessity. The commenter also sees 
large price increases for customers if units are converted to natural 
gas, which is approximately 2.5 times more expensive than the coal that 
the commenter currently uses to generate electricity.
    Response: The EPA's estimates of increase, relative to the 
baseline, in the retail electricity price range from 1.3 percent to 6.3 
percent regionally in 2015, with an average increase nationwide of 3.1 
percent in 2015. Low-income households will thus see some increase in 
electricity price, but this increase should be modest. In addition, the 
increase in the price of natural gas as a result of this rule is 
expected to be 0.3 to 0.6 percent over a time horizon of 2015 to 2030. 
This increase in price is low enough that electricity customers should 
not experience a major increase in price resulting from any modest 
changes to electricity generated by natural gas. The roughly 3 percent 
incremental price effect of this rule is small relative to the changes 
observed in the absolute levels of electricity prices over the last 50 
years, which have ranged from as much as 23 percent lower (in 1969) to 
as much as 23 percent higher (in 1982) than prices observed in 
2010.\351\
---------------------------------------------------------------------------

    \351\ EIA Annual Energy Outlook 2010 annual total electricity 
prices from 1960 to 2010, Table 8-10.
---------------------------------------------------------------------------

c. State or Regional Impacts
    Comment: Multiple commenters expressed concern over the impact of 
the rule on electricity prices and reliability in specific states or 
regions. These commenters were concerned that these impacts would 
adversely affect specific industries such as construction and 
manufacturing. One commenter suggested the EPA consider regional 
differences that will impact system reliability and costs, such as the 
increased impacts on regions relying heavily on coal and oil and 
encourages cooperation between the EPA and state and federal energy and 
environmental regulators.
    Response: The Agency has studied possible impacts on resource 
adequacy as a result of this rule, and has determined that these 
impacts should not be significant. Furthermore, industry, along with 
relevant federal agencies, has the tools needed to address any 
reliability concerns. The Agency has prepared an updated feasibility 
TSD in support of the final rule, which is in the docket for this 
rulemaking.\352\ The Agency has considered impacts on a regional basis 
as part of its overall analyses done using the IPM; these results are 
documented in the RIA for the rule and in the feasibility TSD.
---------------------------------------------------------------------------

    \352\ See ``An Assessment of the Feasibility of Retrofits for 
the Mercury and Air Toxics Standards Rule'' in the docket.
---------------------------------------------------------------------------

    The EPA's analysis shows that retail electricity price increases 
will not fall disproportionately on a specific region. In fact, those 
regions experiencing the largest change in prices are projected to have 
retail electricity prices below the national average both in the 
absence of MATS and after the implementation of MATS. In Chapter 3 of 
the RIA, the EPA presents retail electricity prices by region in 2015, 
for both the base case and MATS policy case. The six regions that are 
projected to have retail electricity prices above the national average 
price in 2015 in the absence of MATS are projected to have increases 
that are below the national average increase following the 
implementation of MATS. Those regions that have projected retail 
electricity price increases that are above the national average are all 
projected to have retail electricity prices below the national average 
in the absence of MATS.
    Comment: A commenter quoted National Mining Association statistics 
showing coal is responsible for $65.738 billion in annual economic 
activity, produces 1,798,800 jobs and $36.345 billion in annual labor 
income. The commenter reports that regions such as Appalachia, the 
Midwest and Rocky Mountain West will be significantly affected by the 
proposed rule, including increased unemployment. Other commenters 
stated that communities near existing coal-fired generation units will 
be especially hard-hit if the plants are permanently retired. The 
communities will suffer from job loss and diminished tax revenue.
    Response: The Agency's analysis, as found in the RIA, shows that 
impacts to these regions are mixed. For Appalachia, coal production is 
projected to fall by 6 percent in 2015, while the Western coal 
producing region will experience a decrease of 3 percent in production 
in 2015. The Interior region is projected to see a 9 percent increase 
in production. Retail electricity prices are expected to increase by 
1.3 percent to 6.3 percent in various parts of the country in 2015. 
Also, the estimated number of early retirements according to the Agency 
that may result from this rule is 4.7 GW in 2015, or less than 2 
percent of all U.S. coal-fired capacity in that year. Thus, there may 
be some negative impacts from this rule in some regions, but these same 
regions will also experience some of the benefits, such as reduced 
premature mortality from less exposure to PM2.5 emissions as 
shown in Chapter 5 of the RIA. As discussed previously, the EPA's 
analysis shows that retail electricity price increases will not fall 
disproportionately on a specific region. In fact, those regions 
experiencing the largest change in prices are projected to have retail 
electricity prices below the national average both in the absence of 
MATS and after the implementation of MATS.
    The results of the EPA's employment analysis, found in Chapter 6 of 
the RIA, indicate that the final MATS has the potential to provide 
significant short-term employment opportunities, primarily driven by 
the high demand for new pollution control equipment. While the 
employment gains related to the new pollution controls are likely to be 
tempered by some losses due to certain coal retirements, some of these 
workers who lose their jobs due to plant retirements could find 
replacement employment operating the new pollution controls at nearby 
units. Finally, job losses due to reduced coal demand are expected to 
be offset by job gains due to increased natural gas demand, resulting 
in a small positive net change in employment due to fuel demand 
changes.
    While shifts in employment are difficult for those directly 
affected, and the Agency remains concerned about the challenges job 
shifts can bring to the

[[Page 9417]]

individuals affected, Bureau of Labor Statistics data indicate that 
compliance with pollution control requirements is a relatively very 
small contributor to overall employment shifts in the U.S. economy. 
Specifically, the main cause of mass layoffs over the last four years 
according to 2007 to 2011 Bureau of Labor Statistics data is ``lack of 
business demand,'' accounting for over 40 percent of the layoffs 
reported by industry. In contrast, all types of regulatory actions 
(including health, safety, and environmental) by all levels of 
government (Federal, State, local) combined were cited as the primary 
factor in only 0.2 percent of mass layoffs over the same period.\353\
---------------------------------------------------------------------------

    \353\ U.S. Bureau of Labor Statistics, 2011. Extended Mass 
Layoffs in 2010. http://www.bls.gov/mls/mlsreport1038.pdf.
---------------------------------------------------------------------------

d. Retirements of Coal-Fired EGUs and Shutdowns
    Comment: A commenter discussed the economic factors behind EGU 
retirements. These factors include the cost of alternative generation 
using natural gas, the cost of implementing demand response measures 
that can be bid into capacity markets, and the cost of continuing to 
generate power from an existing unit. The commenter states that 
regardless of the costs associated with the Toxics Rule and other EPA 
electric power industry regulations, some power plants were already 
economically unsustainable. The commenter quotes M.J. Bradley, who 
points out, ``[o]f the 122 coal units in PJM with capacity less than or 
equal to 200 MW, 35 failed to recover their avoidable costs and another 
52 were close to not recovering those costs. Therefore, in PJM * * * in 
addition to approximately 10 GW of coal generation that has or will be 
retired during the 7 years from 2004 to 2011, another 11 GW faces a 
troubling economic outlook.'' The commenter provides confirmation of 
this by the most recent PJM capacity auction, where approximately 6.9 
fewer GW of coal-fired capacity cleared the auction (1.85 fewer GW were 
offered) as compared with the prior year's auction, and an additional 
4.836 GW of new demand response (energy efficiency) resources cleared 
the auction. Thus, the commenter states, some claims linking 
retirements to the MATS are overstated and misleading. The commenter 
gives the example of the American Electric Power attempt to link its 
planned plant closures to the MATS, but those plants already are slated 
to either close or to upgrade controls to comply with existing laws. 
The commenter goes on to quote three independent studies that support 
the finding that over 50 percent of the fleet is equipped with 
scrubbers and the number will increase to nearly \2/3\ by 2015.
    Response: The EPA agrees with the findings of the independent 
studies mentioned by the commenter.
e. Impacts on Mining
    Comment: Multiple commenters mention the proposed rule's impact on 
mining. One commenter mentioned increasing energy costs for the U.S. 
mining industry, resulting in fewer projects and associated jobs, as 
well as increasing dependence on foreign mineral resources. Commenters 
see mining impacts being disproportionally large for lignite mines, 
which are dependent on their co-located lignite-fired power plants. The 
commenters state that if the plant closes, there is no market for the 
lignite and the mine will also close, displacing plant workers. These 
impacts are largest in Texas, the largest coal consuming state and 
fifth largest coal producing state, as well as a deregulated 
electricity market. One commenter pointed out that the Texas coal 
market provided a buffer against natural gas price volatility and in 
particular believes the proposed rule does not take into account the 
emission reductions already achieved by industry in general and their 
company in particular. A commenter stated that impacts will be 
magnified in Texas, since it is the largest coal consuming state and 
mines lignite. A commenter indicated they believe it is unclear the 
extent to which EPA includes the impacts on the mining industry that 
will result from this rule.
    Response: The Agency presents impacts on the coal mining sector 
from this rule in the RIA. Given the modest increase in coal and other 
energy costs associated with the rule, the Agency does not expect 
widespread impacts on coal mining. The Agency's modeling accounts for 
all emission controls and programs installed and/or implemented up 
through December 2010, including those in Texas.
f. Flexible Regulations
    Comment: Several commenters expressed concern over the potential 
impacts of the regulation and believe that the requirements should be 
more flexible in order to mitigate these impacts.
    Response: The EPA believes the requirements of the final rule have 
been made as flexible as possible consistent with the CAA. The final 
rule allows some flexibility, including allowing averaging across units 
in the same subcategory at a facility, allowing for an option of an 
input or output standard for existing units, and allowing for 
alternative compliance options (e.g., for coal, filterable PM or total 
non-mercury metallic HAP or individual HAP metals). In addition, the 
Agency is not prescribing specific technologies as part of this final 
rule, but instead requiring emissions limitations be met. This approach 
allows the industry to find the most cost-effective approach to meeting 
the requirements while ensuring considerable public health benefits.
g. Temporary vs. Permanent Jobs
    Comment: A commenter expressed disagreement with the EPA prediction 
of new jobs created, because the commenter believes far more plants 
will shut down than the EPA predicts, resulting in higher job losses. 
The commenter also pointed out that while jobs running power plants are 
permanent, the jobs predicted to be created by the proposed rule are 
short term construction jobs, and will all occur in the same short 
timeframe for compliance. The commenter also stated that the EPA 
estimate does not include the opportunity cost of lost construction 
jobs due to new power plants that will not be constructed due to the 
proposed rules.
    Response: The Agency believes that the employment impacts of the 
final rule will be small, as has been the case historically with 
regards to environmental regulation. The Agency does provide an 
estimate of the long-term employment impacts to the electric power 
sector in the RIA for the rule, and that estimate shows a range of 
impacts from 15,000 net jobs lost to 30,000 net jobs gained (all 
annual), but also recognizes important limitations to these estimates. 
The Agency's estimate of impacts to short-term jobs, including those in 
construction, accounts for both losses and gains that result from the 
rule. This is shown in Chapter 6 of the RIA.
    Comment: Commenters believe that installation of new pollution 
controls would be a job-growth opportunity in their states because 
money spent on controls for power plants creates high-quality jobs in 
steel, cement and other materials, as well as in the assembling of the 
equipment as well as installing and operating it. A commenter shares 
the Alabama Fisheries Association estimate that the water-based 
recreation industry brings in over $1 billion per year to the state's 
economy though the state ranks third for imperiled fish with 61 bodies 
of water cited for Hg contamination. The commenter believes the HAP 
accumulating in the waterways

[[Page 9418]]

threatens the industry with permanent job-losses and lost revenue.
    Response: The Agency agrees with the commenter that the reduction 
in HAP that will take place as a result of the rule over time will help 
to improve waterways in Alabama and thus help the water-based 
recreation in that state. More information on the benefits of Hg and 
other HAP reductions can be found in Chapter 4 of the RIA for the rule. 
The Agency also agrees with the commenter that the addition of control 
equipment for EGUs may stimulate employment in a variety of industries.
h. Natural Gas
    Comment: A commenter states that natural gas use is only an option 
in places where infrastructure exists to supply sufficient natural gas 
to the EGU and other local needs and reports that year-round reliable 
gas delivery is rare due to requirements to meet the other needs. The 
commenter says that gas interruptions are prevalent in the winter, but 
can happen year-round, and the costs of establishing a natural gas line 
to a power plant can be tens of millions of dollars or more, and moving 
a plant to a gas source can take many years. The commenter describes 
the options for a Norwalk Harbor plant, and explains that the 
modifications are costly and difficult even before considering the 
modifications needed to alter the boiler and fuel supply system to 
allow natural gas combustion.
    Response: The final rule does not prescribe either pollution 
control technologies to be used, nor does it dictate the types of fuels 
that should be burned. The requirements of the final rule are designed 
to allow industry to find the most cost-effective approach to 
addressing harmful emissions that are covered by this action. The 
Agency believes that cost-effective technologies exist today and have 
been deployed on many power plants, and utilities will be able to find 
intelligent solutions to address harmful emissions. The EPA has 
provided supporting information as part of the preamble and RIA for 
this rule, along with the feasibility TSD, which demonstrate the 
availability and performance of technologies to meet the requirements 
of the final rule.
    Comment: A commenter discusses the factors that could lead to 
higher natural gas prices not currently reflected in the EPA impact 
projections, including industrial load and demand not rebounding to 
2008 levels and the influence of liquefied natural gas exports. The 
commenter asks that the EPA address a variety of factors related to its 
natural gas assumptions.
    Response: The Agency has fully documented its assumptions and 
framework for modeling natural gas in IPM for both the proposed and 
final MATS. This information can be found in Chapter 10 of the IPM 
documentation (http://www.epa.gov/airmarkets/progsregs/epa-ipm/docs/v410/Chapter10.pdf). The documentation provides a thorough overview of 
the natural gas module, describes the very detailed process-engineering 
model and data sources used to characterize North American 
conventional, unconventional, and frontier natural gas resources and 
reserves and to derive all the cost components incurred in bringing 
natural gas from the ground to the pipeline. Also documented are the 
resource constraints, liquefied natural gas (LNG), demand side issues, 
the natural gas pipeline network and capacity, procedures used to 
capture pipeline transportation costs, natural gas storage, oil and 
natural gas liquids (NGL) assumptions, and key gas market parameters.
i. Compliance Timeline and General Timeline
    Comment: A commenter states that the proposed rule will require 
costs be passed on to consumers, meaning state public utility 
commissions will be flooded with requests for rate increases from 
utilities trying to recover expenditures. The short deadline will also 
result in a large number of extension requests made to state permitting 
authorities, further burdening them.
    Response: The compliance date for this rule for existing sources 
will be 3 years and 60 days after publication of the final rule in the 
Federal Register, or approximately March 2015. Thus, there will be some 
time before the impacts of this rule such as any increase in retail 
electricity prices become a concern. It also should be noted that 
increases in retail electricity prices will be 3.1 percent on average 
in 2015, with a range regionally from 1.3 percent to 6.3 percent.
    Comment: A commenter reports that they will need to install add-on 
pollution controls to meet the proposed emission standards as well as 
implement other physical or operational changes. The commenter 
expresses concern about the number of pre-construction steps that would 
be required, as well as the new construction activities and the 
challenges of scheduling sequence relative to interconnections and 
other tie-in considerations involved in compliance.
    Response: The Agency has addressed concerns with the feasibility 
and timing of control installations in its report on the subject (see 
feasibility TSD contained in the docket for this rule).
    Comment: Multiple commenters do not believe that labor availability 
will constrain control installation in the required timeframe and cites 
an Institute of Clean Air Companies (ICAC) response that it will not 
for these reasons:
    1. The power sector has demonstrated ability to install large 
number of systems in short time period;
    2. The majority of coal plans have installed control systems 
already;
    3. Fewer resource and labor-intensive control options being used 
for compliance; and
    4. End users have utilized cost reducing and implementation 
efficiency strategies for efficient deployment of technologies.
    Another commenter states that a wide range of technical and 
economically feasible practices and technologies are available 
currently to meet the emission limits and are in use around the 
country.
    Response: These comments are generally consistent with the 
conclusions of the Agency's analyses on feasibility of control 
installations for this rule as found in the feasibility TSD in the 
docket for this rulemaking.
j. Burden Outweighs Environmental Gain
    Comment: Several commenters state that the EPA has no data relating 
to benefits from reducing non-mercury HAP, so the costs of the proposed 
rule exceed the HAP benefits by 29,000 times. One commenter states that 
the impact analysis was largely focused on Hg with little support for 
other HAP reductions and failed to provide account of true costs and 
benefits.
    Response: While we are not able to monetize the benefits from 
reductions of non-mercury HAP that will take place, these important 
effects are discussed qualitatively in Chapter 4 of the RIA. The 
quantified benefits of this rule include the reductions in non-HAP 
emissions such as SO2 and PM2.5 that will occur 
as a co-benefit of this rule as modeled by EPA. The total benefits are 
estimated to outweigh the total annual costs of the rule by a margin of 
either 3 to 1 or 9 to 1, depending on the benefits estimate and 
discount rate used. These reductions are credible and are considerable 
in size. The estimates of these benefits reflect the latest scientific 
understanding on the subject. More information on the estimates and

[[Page 9419]]

the methodology for their preparation can be found in the RIA for the 
rule.
    Comment: Several commenters consider the proposed rule to be the 
most expensive clean air rule ever. They point out the estimated $10.9 
billion annual cost in 2015 and approximate 1,200 existing coal-fired 
EGUs affected, both of which were estimated by the EPA. Commenters 
believe the EPA's estimates are incorrect and the true cost will be far 
more, due to cumulative effects of all proposed power sector rules, and 
indirect costs from job losses, reduced productivity and 
competitiveness resulting from electricity costs. They ask the EPA to 
keep these high costs in mind when evaluating impacts of the proposed 
rule and consider the costs with respect to the benefits. One commenter 
requests that the EPA explain how its approach utilized ``the best 
available techniques to quantify anticipated present and future 
benefits and costs as accurately as possible'' and includes analyses by 
EIA, EEI, NERC, NERA, Credit Suisse, ICF, and Burns & McDonnell.
    Response: As noted earlier, the Agency did not prepare a cumulative 
impact analysis to accompany the rule for the following reasons: (1) 
The various EO requirements that the Agency must comply with require us 
to estimate impacts specific to this rule; (2) decisionmakers and the 
public need to know the impacts specific to a particular rule in order 
to judge the merits of the regulation; and (3) estimates specific to a 
particular rule are more transparent than those from a cumulative 
impact analysis. A cumulative impact analysis lumps several regulations 
together and can potentially mask a high-cost/low benefit regulation 
among other rules that may have large net benefits. By analyzing each 
regulation separately, EPA makes clear statements about the impacts, 
costs, and benefits that are estimated as a result of this particular 
regulation.
    This does not, however, mean EPA has failed to incorporate these 
regulations into this analysis. The inclusion of CSAPR and other 
regulatory actions (including federal, state, and local actions) in the 
IPM base case reflects the level of controls that are likely to be in 
place in response to other requirements apart from MATS. This base case 
provides meaningful projections of how the power sector will respond to 
the cumulative regulatory requirements for air emissions, while 
isolating the incremental impacts of MATS. These results are presented 
in Chapter 3 of the RIA.
    Additionally, the Agency does reflect on the cumulative impacts of 
our regulations. In March 2011, EPA issued the Second Clean Air Act 
Prospective Report which assessed the benefits and costs of regulations 
pursuant to the 1990 Clean Air Act Amendments. The study examines the 
cumulative impact of these regulations (found at http://www.epa.gov/air/sect812/feb11/summaryreport.pdf). As shown in the report, the 
direct benefits from the 1990 Clean Air Act Amendments are estimated to 
reach almost $2 trillion for the year 2020, a figure that dwarfs the 
direct costs of implementation ($65 billion). The full report is at 
http://www.epa.gov/air/sect812/prospective2.html.
    The direct benefits of the 1990 Clean Air Act Amendments and 
associated programs are estimated to significantly exceed their direct 
costs, which means economic welfare and quality of life for Americans 
were improved by passage of the 1990 Amendments. The wide margin by 
which benefits are estimated to exceed costs, combined with extensive 
uncertainty analysis, suggest it is very unlikely this result would be 
reversed using any reasonable alternative assumptions or methods. The 
analysis presented in the RIA for the current regulation uses a similar 
methodology.
    The techniques employed by the Agency for generating benefits and 
costs, and consider the most recent and complete data available to the 
Agency. The EPA recognizes that the analyses have caveats and 
limitations, and we discuss our analyses and their caveats and 
limitations in the RIA for the rule, as well as in the benefits section 
of the preamble. The Agency has also revised the cost analyses for the 
final rule to reflect data received in public comments on the proposed 
rule, and costs are lower than when the rule was proposed.
k. Impact on State Regulators
    Comment: Several commenters expressed concern over the burden 
imposed on state regulatory agencies by the rule.
    Response: The Agency has estimated the costs of implementation of 
the rule to states that own EGUs affected by the rule, and has included 
this analysis in the RIA. The Agency has updated this analysis for the 
final rule and it is included in the RIA. While the EPA has not 
prepared an analysis of the impacts of the rule on state programs, the 
Agency does not believe the rule will be unduly burdensome to the state 
regulatory agencies. The EPA works closely with state regulatory 
authorities to ensure that the rules are implemented properly, and the 
Agency will continue to do so in support of this final rule.
    Comment: A commenter states that the reductions in SO2 
and PM2.5 required by the proposed rule will assist state 
and local air pollution control agencies to meet health-based air 
quality standards, reduce haze and improve visibility. The commenter 
points out that substantial reduction in emissions made by the very 
large sources under the proposed rule will lead to fewer pollution 
controls needed at smaller sources to meet health-based ambient air 
requirements. This is a far more cost-effective approach than controls 
at smaller facilities and is the lowest cost path to improved public 
health and a cleaner environment.
    Response: The EPA acknowledges that the HAP standards in this final 
rule will lead to considerable co-benefit reductions in PM and 
SO2.
l. Miscellaneous
    Comment: A few commenters discussed the impact of the rule on the 
federal budget deficit. One commenter points out that the proposed rule 
will affect the federal budget in two ways:
    1. Direct compliance costs to electric generating units (EGUs) 
owned by federal agencies; and
    2. Pass-through compliance costs paid in the form of higher prices 
for electricity purchased by federal agencies.
    Response: The Agency estimates the direct compliance costs to EGUs 
that are federally owned as part of the overall cost analysis completed 
for the proposal and disclosed in the RIA for the rule. The Agency does 
not provide an estimate of the impact on federal agencies from higher 
electricity prices associated with the rule, however. This type of 
analysis is not required under EO 12866 and statutory requirements.

H. Testing and Monitoring

    Comment: Commenters raised numerous issues with the testing and 
monitoring requirements for initial and continuous compliance. The 
following discussion highlights the comments and responses to a number 
of the critical issues and describe where the comments have resulted in 
a significant rule change or where we disagreed with commenters' 
suggestions of issues or need for changes in the rule. Additional 
comments and responses are addressed in the Response to Comments 
document included in the docket for the final rule.
    Test Methods. A number of commenters suggested that we should allow 
for the use of Method 5B to determine compliance with the PM emission 
limit. In addition, a number of

[[Page 9420]]

commenters objected to the frequency of stack testing when used as the 
method for demonstrating continuous compliance. Commenters also 
objected to the requirement for testing one pollutant when the source 
was complying with an optional surrogate (or vice versa); for example, 
commenters objected to testing for HCl if a unit was complying with the 
optional SO2 limit, or testing for metals if the unit was 
complying with the optional PM limit.
    Response: Although Method 5B is specified for wet scrubber-
controlled utility boilers under 40 CFR part 60, subparts D, Da and Db, 
we are excluding Method 5B for demonstrating compliance with the 
filterable PM emissions standard in this final rule. The extended high 
temperature heating of the filters prior to weighing as specified in 
Method 5B would introduce differences between the compliance test data 
and the data that underlie the filterable particulate standard. Because 
the test data that underlie and filterable particulate standard are 
based primarily on Method 29 and Method 5 data collected at 
320[emsp14][deg]F or comparable filterable particulate methods, we are 
specifying those same methods for determining compliance with the 
standard.
    For stack test frequency, we modified the final rule to require 
quarterly testing to demonstrate continuous compliance. In addition, we 
agree that testing should be required only for the emission limits that 
your source is complying with, and, thus, the final rule does not 
require testing of both the pollutant and the surrogate.
    Comment: Fuel Analysis Methods. A number of commenters raised 
various concerns with the fuel analysis methods specified in the 
proposed rule.
    Response: Based on the comments received and a further review of 
the technical challenges associated with the proposed fuel analysis 
requirements, we have not finalized the proposed fuel analysis 
requirements. As the rule no longer requires operating limits based on 
fuel content or fuel analysis, the comments on this issue are largely 
moot. For LEEs, we agree that the proposed LEE ongoing eligibility 
requirements were overly burdensome and restrictive. As a result, 
existing solid or liquid fired units that qualify for Hg LEE status 
will be required to conduct a 30-day test for Hg using Method 30B each 
year. Neither fuel analysis nor adherence to an operating limit will be 
required. Should an annual test show ineligibility for LEE status, the 
source will revert to the requirements for Hg monitoring using CEMS or 
sorbent traps or, for oil-fired units, quarterly emissions testing. 
Existing solid or liquid fired units that qualify for non-mercury LEE 
status will be required to conduct a stack test every 3 years, and 
neither fuel analysis nor adherence to an operating limit will be 
required. Should the stack test show ineligibility for LEE status, the 
source will revert to using CEMS or PM CPMS or conducting quarterly 
emissions testing.
    Comment: Operating Parameter Limits: Some commenters objected to 
the use of enforceable operating parameter limits, requested that the 
rule be more consistent with the compliance assurance monitoring 
program, and raised specific objections to certain parameters required 
for certain control devices. Commenters also raised concerns about a PM 
CEMS operating limit establishing a de facto more stringent PM emission 
limit than the one being tested for under the total PM standard in the 
proposal.
    Response: We believe that continuous monitoring in the form of 
CEMS, sorbent trap monitoring systems, and PM CPMS, or frequent stack 
emissions testing are appropriate to ensure ongoing compliance with 
this final rule. We also agree with commenters that some of the 
monitoring provisions in the proposal may have been duplicative and 
unnecessary. In order to provide flexibility in the final rule, we have 
retained a source's ability to define an operating limit and to monitor 
using a PM CPMS as an option to periodic filterable PM emissions 
testing.
    The final rule establishes the PM CPMS as an operating limit 
monitor and not a direct filterable PM emission monitoring requirement 
that meets PS 11 requirements. Although we recognize the importance of 
continued control device performance to ensure emissions minimization, 
we also are aware that other rules that apply to these units including, 
but not limited to, the Operating Permits rule, the Compliance 
Assurance Monitoring rule, the ARP rules, and the NSPS already require 
continuous monitoring in most cases. Those rules will remain in effect 
so the need to impose additional operating limits monitoring or CEMS on 
those units is much reduced.
    The final rule also provides for the use of a PM CEMS to determine 
compliance with the filterable PM emission limit if the source elects 
to use this approach. In that case, the PM CEMS is used as the direct 
method of compliance and no additional testing is required other than 
tests that are required as part of satisfying the requirements in 
Performance Specification 11 in Appendix B to 40 CFR part 60 and 
Procedure 2 in Appendix F to part 60. The EPA provided this option in 
response to the comments in order to provide a straightforward direct 
measure of compliance that some sources may want to implement.
    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 40 CFR 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 
CAMR-based requirements for Hg monitoring in place of the general 40 
CFR part 63 performance specifications and QA requirements. 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 gas standards will be adequate and consistent with 
existing applications of Hg CEMS. For the lowest limits and other 
applications where an integrated sampling system offers advantages, 
affected facilities may opt to use sorbent trap monitoring systems to 
comply. There are data in the recent draft report entitled 
``Determining the Variability Of CMMS At Low Hg Levels,''\354\ that 
demonstrate reasonable

[[Page 9421]]

performance of at least one Hg CEMS at Hg levels below 1.0 microgram 
per cubic meter ([mu]g/m3) down to approximately 0.1 [mu]g/
m3. 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.
---------------------------------------------------------------------------

    \354\ http://www.icci.org/reports/10Laudal6A-1.pdf.
---------------------------------------------------------------------------

    Comment: SO2 CEMS: Although commenters were generally 
supportive of the ability to use SO2 CEMS for units with FGD 
installed to demonstrate compliance with an alternate SO2 
emission limit instead of the HCl emission limit, there were some 
concerns with aspects of the proposal. Commenters requested that the 
SO2 monitoring requirements rely on 40 CFR part 75 given 
that their sources were already meeting those requirements and that 
this rule not establish any new requirements, especially a fourth 
linearity level and the application of 7-day calibration error tests 
for units with low concentrations (where 40 CFR 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 the requirement 
for a linearity check even for SO2 monitors with low span 
values (<= 30 ppm). A source 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 40 CFR part 75 
reporting. The requirement for a 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. Those concerns were 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 
emission limits set in the final rule. 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 generic 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 Fourier Transform Infrared (FTIR)-based HCl CEMS and/or 
HF CEMS complying with Appendix B to the rule which relies on PS 15,
    (2) Seeking approval for an alternative HCl monitoring procedure 
through 40 CFR 63.7(f),
    (3) Monitoring compliance continuously with the alternate 
SO2 emission limit at coal-fired or other solid fuel 
affected facilities equipped with FGD technology for SO2, 
and
    (4) Quarterly 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 new, non-technology-specific EPA performance specifications becomes 
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 for reporting when emissions are vented 
to a bypass stack. That approach works within the context of an 
emissions trading program, but is not appropriate when evaluating 
compliance with a specific emission limit. Thus, we have provided two 
other options. One is to monitor the bypass stack, consistent with the 
final rule. The other is to treat any hours of bypass stack emissions 
as periods of monitor downtime and hours of deviation from the 
monitoring requirements. Note that a source's units must continue to 
meet their 30-boiler operating day emissions limits during malfunction 
periods.
    Comment: 40 CFR part 75 Issues. There were a number of general 
comments about the value of relying on 40 CFR part 75 requirements, 
including elements such as conditional data validation. The commenters 
generally agreed that the 40 CFR part 75 bias test and bias adjustment 
factor, and the 40 CFR 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 40 CFR part 75 wherever appropriate. 
One of those examples is the inclusion of conditional data validation 
for Hg CEMS. We disagree 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 (30-boiler operating 
day) emissions rate limit. We agree that data quality certainty 
associated with any calculated value decreases with the collection of 
less data such as would occur with extended periods of monitoring 
system downtime. Even so, we believe also that it is necessary and 
critical for compliance with the regulation that a source use 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 a specified 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 if these deviations 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 are not requiring 
data substitutions under this rule. We believe, however, that 
defensibility concerns make it incumbent on the source 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

[[Page 9422]]

requirements. Should the source or the enforcement authority be 
concerned about the representativeness of data such as during periods 
of missing data, either one 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 failure to collect required or 
otherwise excepted data as 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 recordkeeping and retention requirements 
are consistent with other requirements already in place, specifically 
40 CFR 63.10 (b).
    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 most continuously measured pollutants and we 
will make these modifications for receipt of the additional CEMS data. 
We also recognize the need for substantial modifications to the ECMPS 
to accommodate the data needs for periodically measured pollutants and 
certain CEMS data such as PM CEMS data and possibly HAP metals CEMS 
data. Although major modifications of the ECMPS would be required for 
periodic compliance tests by isokinetic and instrumental test methods 
(as well as certain types of CEMS), only 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 federal 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.

I. Emissions Averaging

    Comment: In response to our request for comments on the suitability 
of emissions averaging and need for a discount factor, we received a 
range of suggestions, including requests for clarification regarding 
eligibility, points for and against the need for a discount factor, and 
suggestions to ease implementation.
    Response: We are finalizing that owners and operators of existing 
affected sources may demonstrate compliance by emissions averaging for 
EGUs at the affected source that are within a single subcategory and 
that rely on emissions testing as the compliance demonstration method. 
See section VI of thie preamble for a fuller discussion.

J. LEE Criteria

    Comment: A commenter supported the LEE provisions but believed one 
of the LEE eligibility criteria should set at 29.0 lb/year, rather than 
22.0 lb/year. The commenter suggested 29.0 lb/year to be an equally 
reasonable cut point, especially since that value matches the low mass 
emitter Hg monitoring cutoff in CAMR and the low mass emitter Hg 
monitoring cutoff that several states have adopted, including Illinois, 
35 Ill. Admin. Code section 225.240(a)(4). (See, e.g., Colorado (5 
Colo. Code Regs. section 1 00 1-8, Reg. No.6, part B, Section 
VIII.B.l0); Michigan (Mich. Admin. Code R. 336.2160); Montana (Mont. 
Admin. R. 17.8771(12))). Further, a LEE cutoff of 29.0 lb would 
eliminate conflicts and confusion with low mass emitter provisions in 
existing state Hg

[[Page 9423]]

programs and significantly reduce compliance costs and burdens for the 
additional qualifying units without adversely affecting compliance 
assurance with the EGU NESHAP Hg emission limits or materially 
increasing the number of potential qualifying LEEs. Given the many 
other costly burdens that the rule would impose, the benefit of LEE to 
a qualifying unit is not insignificant.
    Response: The Agency reviewed the commenter's suggestions, and one 
of the LEE eligibility criteria in the rule has been revised from 22.0 
to 29.0 lb of Hg per year. The Agency finds the result of consistency 
with existing state regulations outweighs the two percent difference in 
nationwide Hg mass emissions, from 5 percent to 7 percent, for LEE 
eligibility.

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. The level of control prescribed by CAA section 111 
historically has been referred to as ``Best Demonstrated Technology'' 
or BDT. In order to better reflect that CAA section 111 was amended in 
1990 to clarify that ``best systems'' may or may not be ``technology,'' 
the EPA is now using the term ``best system of emission reduction'' or 
BSER. As was done previously in analyzing BDT, the EPA uses available 
information and considers the emission reductions and incremental costs 
for different systems available at reasonable cost. Then, the EPA 
determines the appropriate emission limits representative of BSER. 
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 for EGUs 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 NOP2 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 BSER 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 the Final NSPS

    The final rule amends the emission standards for SO2, 
NOP2, and PM in 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 testing, monitoring, 
and other compliance provisions similar to those 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 essentially equivalent to the 
existing requirements of 13 ng/J (0.015 lb/MWh) heat input regardless 
of the type of fuel burned. Compliance with this emission limit can be 
determined using testing, monitoring, and other compliance provisions 
similar to those 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 EPA 
neither proposed to amended the SO2 standard for coal 
refuse-fired EGUs, not reopened the issue of whether coal refuse-fired 
EGUs is an appropriate subcategory, and, therefore, that emissions 
standard is unchanged. 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. Compliance with the SO2 emission limit 
is determined on a 30-boiler operating 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 exception is that for new and 
reconstructed EGUs that burn over 75 percent coal refuse (by heat 
input), the NOX emission limit 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-boiler operating day rolling average basis using testing, 
monitoring, and other compliance provisions similar to those in the 
proposed rule.
    As an alternative 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 exception is that for new

[[Page 9424]]

and reconstructed EGUs that burn over 75 percent coal refuse (by heat 
input) on an annual basis, the NOX/CO emission limit 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 rationale for 
this is set forth in the Response to Comments (RTC) document for this 
final rule (the NSPS Final Rule RTC).
    The proposal requested comment on whether the final standard should 
include a stand-alone NOX standard or a combined 
NOX/CO standard. In response to comments we received and our 
own further evaluation of the situation, the final standard includes a 
stand-alone NOX standard and an optional, but not required, 
combined NOX/CO standard as an alternative to the amended 
NOX standard. Again, our full rationale for this is set 
forth in the NSPS Final Rule RTC. The proposal also included a request 
for comment on whether the standard should be based on gross or net 
output. In response to comments we received and our own further 
evaluation of the situation, the final standards are based on an 
amended definition of gross output with an optional net output-based 
standard. This too is addressed more fully in the NSPS Final Rule RTC.
    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. Advanced combustion controls are applicable to existing 
facilities and the exemption is not necessary to further the 
development of the technology.

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 for PM in lieu of numeric emission 
limits. Emissions incurred during periods of startup and shutdown for 
PM are not used in demonstrations of compliance with the 30-boiler 
operating day rolling average period applicable for numeric emission 
standards.

XI. Public Comments and Responses to the Proposed NSPS

    See the Response to Comments document.

XII. Impacts of the Final Rule

    The EPA anticipates significant public health and environmental 
benefits from the rule as a direct result of the substantial reduction 
in the emissions of several pollutants, including SO2, Hg, 
acid gases and fine particles and metals. For example, exposure to Hg 
can damage the developing nervous system, which can impair children's 
ability to think and learn, and fine particles can cause adverse 
cardiovascular effects. Further, reducing Hg deposition to ecosystems 
will benefit wildlife including fish, birds, and mammals. Fish and 
fish-eating birds, such as the common loon, and mammals suffer 
reproductive, survival, and behavioral impairments due to mercury 
exposure. These effects have also been observed in insect-eating and 
wading birds, including egrets and white ibis. Reductions of emissions 
targeted by this rule also will slow acidification and eutrophication 
of water bodies.
    Additionally, the EPA anticipates significant non-health, non-
ecological benefits from this rule. The fine particle and 
SO2 emission reductions achieved by this rule will improve 
visibility, which is especially important for our national parks. 
Emissions reductions from this rule will also avoid an estimated $360 
million (in $2007) of climate-related costs, such as agricultural 
productivity and property damage from increased flood risks.

A. What are the air impacts?

    The EPA anticipates significant emission reductions under the final 
rule from coal-fired EGUs, which are of particular interest 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 75 percent, and PM2.5 emissions reduced by 19 
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 EGUs greater 
than 25 MW by 2015, relative to the base case. See Table 7.

                                  Table 7--Summary of Emission Reductions From Coal-Fired EGUS Greater Than 25 MW (TPY)
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                          SO2  (million      NOX  (million                         HCl  (thousand    PM2.5  (thousand    CO2  (million
                                              tons)              tons)         Mercury  (tons)         tons)              tons)          metric tonnes)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Base Case.............................                3.3                1.7                 27                 45                270              1,906
MATS..................................                1.9                1.7                  7                  6                218              1,882
Change................................               -1.4                0.0                -20                -40                -52                -23
--------------------------------------------------------------------------------------------------------------------------------------------------------
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 gases. 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 emission 
reductions.

 B. What are the energy impacts?

    The EPA projects that approximately 4.7 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 
may be removed from operation by 2015. These units are predominantly 
smaller, less frequently used, and are 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

[[Page 9425]]

make further investments in these facilities and keep these units 
operational.
    The final rule has other important energy market implications. 
Average nationwide retail electricity prices are projected to increase 
in the contiguous U.S. by 3.1 percent in 2015. The average delivered 
coal price is projected to increase 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 between 0.3 and 0.6 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 10 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 direct power industry expenditures to 
comply with the EPA's requirements.
    The EPA projects that the annual incremental compliance cost of 
MATS is $9.6 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.
    The total incremental compliance cost includes compliance costs 
modeled in IPM of $9.4 billion, costs modeled outside of IPM for oil-
fired EGUs of $56 million, and monitoring, reporting, and recordkeeping 
costs of $158 million.

D. What are the economic impacts?

    For this final rule, EPA analyzed the costs using the IPM. The 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.
    The EPA performed a screening analysis for impacts on small 
entities by comparing compliance costs to sales/revenues (e.g., sales 
and revenue tests). The EPA's analysis can be found in Chapter 7 of the 
RIA for this rule. The EPA has also prepared a Final Regulatory 
Flexibility Analysis (FRFA) that discusses alternative regulatory or 
policy options that minimize the rule's small entity impacts.
    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. 
Executive Order 13563 specifically states that our ``regulatory system 
must protect public health, welfare, safety, and our environment while 
promoting economic growth, innovation, competitiveness, and job 
creation'' (emphasis added).
    Under conditions of full employment, it is conventional to assume 
that regulations will merely shift jobs from one sector to another, 
without having a material effect on employment levels. Potential 
employment effects are of greater concern in the current economic 
climate, with high levels of employment, because of the risk that 
displaced workers may not find alternative jobs. In addition, 
regulations that result in firms hiring workers, in order to ensure 
compliance, may have a positive effect on employment.
    During sustained periods of excess unemployment, 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). Consistent with EO 13563, the EPA includes estimates of job 
impacts associated with the final rule. In the electricity sector, the 
EPA estimates that the net employment effect will range from -15,000 to 
+30,000 jobs, with a central estimate of +8,000. The EPA also presents 
an estimate of short-term employment effects as a result of increased 
demand for pollution control equipment.
    The results of this analysis, found in Chapter 6 of the RIA, 
indicate that the final rule has the potential to provide increases in 
short-term employment in the environmental industry, primarily driven 
by the high demand for new pollution control equipment. Overall, the 
results suggest that the final rule could support a net of roughly 
46,000 job years \355\ in direct employment impacts in 2015.
---------------------------------------------------------------------------

    \355\ Numbers of job years are not the same as numbers of 
individual jobs, but represents the amount of work that can be 
performed by the equivalent of one full-time individual for a year 
(or FTE). For example, 25 job years may be equivalent to five full-
time workers for five years, 25 full-time workers for one year, or 
one full-time worker for 25 years.
---------------------------------------------------------------------------

    There are other employment effects that cannot be estimated 
quantitatively at this time. The employment gains related to the new 
pollution controls are likely to be tempered by some losses due to 
certain coal retirements. On the other hand, some of those workers who 
lose their jobs due to plant retirements could find alternative 
employment operating the replacement electricity generating equipment 
or new pollution controls at nearby units. Finally, job losses due to 
reduced coal demand may be offset by job gains due to increased natural 
gas demand, potentially resulting in a positive net change in 
employment due to fuel demand changes.
    The basic approach to estimate these employment impacts involved 
using IPM projections from the final rule analysis, in particular the 
amount of existing coal-fired capacity that is projected to be retrofit 
with pollution control technologies. These data, along with data on 
labor and resource needs of new pollution controls and labor 
productivity from engineering studies and secondary sources, are used 
to estimate employment impacts for the pollution control industry in 
2015. For more information, please refer to Chapter 6 and appendix 6B 
in the RIA.
    The EPA relied on Morgenstern, et al., (2002), to identify three 
economic mechanisms by which pollution abatement activities can 
influence jobs in the regulated sector separately from the short-term 
employment effects:
    [ssquf] Higher production costs raise market prices, higher prices 
reduce consumption, and employment within an industry falls (``demand 
effect'');
    [ssquf] Pollution abatement activities require additional labor 
services to produce the same level of output (``cost effect''); and
    [ssquf] 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,

[[Page 9426]]

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 spent on pollution abatement results in a small net increase of 
1.55 jobs; the estimated effect is not a statistically different from 
zero. As a result, the authors conclude that increases in pollution 
abatement expenditures may increase employment in the relevant sectors 
and do not necessarily cause economically significant employment 
changes. The conclusion is similar to that of Berman and Bui (2001) who 
found that increased air quality regulation in Los Angeles did not 
cause large employment changes.\356\ For more information, please refer 
to Chapter 6 of the RIA for this final rule.\357\
---------------------------------------------------------------------------

    \356\ For alternative views in economic journals, see Henderson 
(1996) and Greenstone (2002).
    \357\ It should be noted that if more labor must be used to 
produce a given amount of output, then this implies a decrease in 
labor productivity. A decrease in labor productivity will cause a 
short-run aggregate supply curve to shift to the left, and 
businesses will produce less, all other things being equal.
---------------------------------------------------------------------------

    In the directly affected sector, the EPA estimates that the net 
employment effect will range from -15,000 to +30,000 jobs, with a 
central estimate of +8,000. The ranges of job effects for the 
electricity sector, as 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   -3.56........................  2.42.........................  2.68.........................  1.55.
 Million Dollars of
 Environmental Expenditure a.
Standard Error...............  2.03.........................  0.83.........................  1.35.........................  2.24.
EPA estimate for Final Rule b  -39,000 to...................  +4,000 to....................  +200 to......................  -15,000 to
                               +2,000.......................  +21,000......................  +27,000......................  +30,000.
--------------------------------------------------------------------------------------------------------------------------------------------------------
\a\ Expressed in 1987 dollars. See footnote a from Table 6-2 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 that are not 
considered in the Morgenstern,et al., study. Although EPA has 
considered some economy-wide changes, we do not have sufficient 
information to quantify other job effects associated with 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. The NAS Study (NRC, 
2000) provides a thorough review of the effects of MeHg on human 
health. Many of the peer-reviewed articles cited in this section are 
publications originally cited in the NAS Study. In addition, the EPA 
has conducted literature searches to obtain other related and more 
recent publications to complement the material summarized by the NAS 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 concluded that they are 
appropriate for establishing an RfD (NRC, 2000); in particular NAS 
supported the use of results from neurobehavioral or neuropsychological 
tests. The NAS Study (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 neurodevelopmental 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 NAS Study 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 report 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 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 Study indicated 
that evidence that human exposure to MeHg causes 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 Tapaj[oacute]s 
River region in Brazil (Amorimet 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

[[Page 9427]]

seen in the populations studied in the Faroe Islands and Republic of 
Seychelles.
    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).
    Some evidence of reproductive and renal toxicity in humans from 
MeHg exposure exists. However, overall, human data regarding 
reproductive, renal, and hematological toxicity from MeHg are very 
limited and are based on 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 \358\ 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 \359\ much 
of the focus has been on large piscivorous species, in particular the 
common loon. According to Evers,et al., significant adverse effects 
from Hg on breeding loons have been found to occur, including 
behavioral (reduced nest-sitting), physiological (flight feather 
asymmetry) and reproductive (chicks fledged/territorial pair) effects 
and reduced survival.\360\ Additionally, Evers, et al., (see footnote 
5), 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.
---------------------------------------------------------------------------

    \358\ Crump, KL, and Trudeau, VL. Mercury-induced reproductive 
impairment in fish. Environmental Toxicology and Chemistry. Vol. 28, 
No. 5, 2009.
    \359\ U.S. Environmental Protection Agency (EPA). 1997. Mercury 
Study Report to Congress. Volume V: Health Effects of Mercury and 
Mercury Compounds. EPA-452/R-97-007. U.S. EPA Office of Air Quality 
Planning and Standards, and Office of Research and Development; U.S. 
Environmental Protection Agency (U.S. EPA). 2005. Regulatory Impact 
Analysis of the Final Clean Air Mercury Rule. Research Triangle 
Park, NC., March; EPA report no. EPA-452/R-05-003. Available on the 
Internet at http://www.epa.gov/ttn/ecas/regdata/RIAs/mercury_ria_final.pdf.
    \360\ Evers, DC, Savoy, LJ, DeSorbo, CR, Yates, DE, Hanson, W, 
Taylor, KM, Siegel, LS, Cooley, JH, Jr., Bank, MS, Major, A, Munney, 
K, Mower, BF, Vogel, HS, Schoch, N, Pokras, M, Goodale, MW, Fair, J. 
Adverse effects from environmental mercury loads on breeding common 
loons. Ecotoxicology. 17:69-81, 2008; Mitro, MG, Evers, DC, Meyer, 
MW, and Piper, WH. Common loon survival rates and mercury in New 
England and Wisconsin. Journal of Wildlife Management. 72(3): 665-
673, 2008.
---------------------------------------------------------------------------

    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. White 
ibis have been observed to have decreased foraging efficiency\361\ and 
have been shown to exhibit decreased reproductive success and altered 
pair behavior.\362\ In egrets, Hg has been implicated in the decline of 
the species in south Florida,\363\ and Hoffman\364\ has shown that 
egrets exhibit 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.
---------------------------------------------------------------------------

    \361\ Adams, EM, and Frederick, PC. Effects of methylmercury and 
spatial complexity on foraging behavior and foraging efficiency in 
juvenile white ibises (Eudocimus albus). Environmental Toxicology 
and Chemistry. Vol 27, No. 8, 2008.
    \362\ Frederick, P, and Jayasena, N. Altered pairing behavior 
and reproductive success in white ibises exposed to environmentally 
relevant concentrations of methylmercury. Proceedings of The Royal 
Society B. doi: 10-1098, 2010.
    \363\ Sepulveda, MS, Frederick, PC, Spalding, MG, and Williams, 
GE, Jr. Mercury contamination in free-ranging great egret nestlings 
(Ardea albus) from southern Florida, USA. Environmental Toxicology 
and Chemistry. Vol. 18, No. 5, 1999.
    \364\ Hoffman, DJ, Henny, CJ, Hill, EF, Grover, RA, Kaiser, JL, 
Stebbins, KR. Mercury and drought along the lower Carson River, 
Nevada: III. Effects on blood and organ biochemistry and 
histopathology of snowy egrets and black-crowned night-herons on 
Lahontan Reservoir, 2002-2006. Journal of Toxicology and 
Environmental Health, Part A. 72: 20, 1223-1241, 2009.
---------------------------------------------------------------------------

    Insectivorous birds have also been shown to suffer adverse effects 
due to Hg exposure. 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,\365\ had lower survival rates,\366\ and had compromised 
immune competence.\367\ The great tit has exhibited reduced singing 
behavior and smaller song repertoire in areas of high 
contamination.\368\
---------------------------------------------------------------------------

    \365\ Brasso, RL, and Cristol, DA. Effects of mercury exposure 
in the reproductive success of tree swallows (Tachycineta bicolor). 
Ecotoxicology. 17:133-141, 2008.
    \366\ Hallinger, KK, Cornell, KL, Brasso, RL, and Cristol, DA. 
Mercury exposure and survival in free-living tree swallows 
(Tachycineta bicolor). Ecotoxicology. Doi: 10.1007/s10646-010-0554-
4, 2010.
    \367\ Hawley, DM, Hallinger, KK, Cristol, DA. Compromised immune 
competence in free-living tree swallows exposed to mercury. 
Ecotoxicology. 18:499-503, 2009.
    \368\ Gorissen, L, Snoeijs, T, Van Duyse, E, and Eens, M. Heavy 
metal pollution affects dawn singing behavior in a small passerine 
bird. Oecologia. 145: 540-509, 2005.
---------------------------------------------------------------------------

    In mammals, adverse effects have been observed in mink and river 
otter, both fish eating species. For otter from Maine and Vermont, 
maximum concentrations of Hg in fur nearly equal or exceed a level 
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.\369\ Adverse 
sublethal effects may be associated with lower Hg concentrations and 
consequently may 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.\370\
---------------------------------------------------------------------------

    \369\ Yates, DE, Mayack, DT, Munney, K, Evers DC, Major, A, 
Kaur, T, and Taylor, RJ. Mercury levels in mink (Mustela vison) and 
river otter (Lonra canadensis) from northeastern North America. 
Ecotoxicology. 14, 263-274, 2005.
    \370\ Scheuhammer, AM, Meyer MW, Sandheinrich, MB, and Murray, 
MW. Effects of environmental methylmercury on the health of wild 
birds, mammals, and fish. Ambio. Vol.36, No.1, 2007.
---------------------------------------------------------------------------

    h. Methodology for Partial Hg Benefits Estimation. The EPA has 
conducted a national-scale analysis of the benefits to recreational 
anglers of avoided IQ loss related to reductions of Hg emissions

[[Page 9428]]

and subsequent deposition that will be achieved by this rule. 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 of 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 National Survey of Fishing, 
Hunting, and Wildlife-Associated Recreation (FHWAR) data.
    Data from the 1994 National Survey on Recreation and the 
Environment (NSRE) 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' 
prenatal ingestion of Hg from fish 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, the 
following dose-response relationship was developed 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 potential 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 Bureau 
of Labor Statistics 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) in increased earnings per year per 1-point IQ increase. With 
a 7 percent discount rate assumption, the value IQ estimates range from 
$893 to $1,958 in increased earnings per year per 1-point IQ increase.
    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-year value of these 
losses ranges from $204.8 million to $292.5 million nationally.\371\ 
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-year value range is considerably lower: $22.8 million to $50.0 
million.
---------------------------------------------------------------------------

    \371\ Monetized benefits estimates are for an immediate change 
in MeHg levels in fish. If a lag in the response of MeHg levels in 
fish were assumed, the monetized benefits could be significantly 
lower, depending on the length of the lag and the discount rate 
used. As noted in the discussion of the Mercury Maps modeling, the 
relationship between deposition and fish tissue MeHg is proportional 
in equilibrium, but the Mercury Maps approach does not provide any 
information on the time lag of response.
---------------------------------------------------------------------------

    For this rule, 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 
MATS 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. The EPA 
recognizes that these calculated benefits are a small subset of the 
benefits of reducing Hg emissions.
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 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 may 
result from decreases in PM2.5 morbidity impacts, decreases 
in sulfur deposition and direct health effects of SO2, and 
improvements in visibility in national parks and wilderness areas. 
Total co-benefits may be higher than the partial estimates of co-
benefits provided here. Our best estimate of the monetized health and 
climate co-benefits of this rule in 2016 at a 3 percent discount rate 
are $37 billion to $90 billion or $33 billion to $81 billion at a 7 
percent discount rate (2007$). 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.\372\
---------------------------------------------------------------------------

    \372\ Roman, et al., 2008. Expert Judgment Assessment of the 
Mortality Impact of Changes in Ambient Fine Particulate Matter in 
the U.S. Environ. Sci. Technol., 42, 7, 2268-2274.
---------------------------------------------------------------------------

    a. Human Health Co-Benefits. To estimate the human health co-
benefits of this rule, the EPA used benefit-per-ton

[[Page 9429]]

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),\373\ but for this rule 
the air quality modeling used a better spatial representation of the 
emission changes from EGUs. Using a benefit-per-ton approach adds 
another important source of uncertainty to the benefits estimates. 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.
---------------------------------------------------------------------------

    \373\ Fann, N., C.M. Fulcher, B.J. Hubbell. 2009. ``The 
influence of location, source, and emission type in estimates of the 
human health benefits of reducing a ton of air pollution.'' Air Qual 
Atmos Health (2009) 2:169-176.
---------------------------------------------------------------------------

    Table 9 presents the estimates of reduced annual incidence of 
PM2.5-related health effects in 2016 resulting from this 
rule. Table 10 presents the estimated annual monetary value of the 
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 estimated health co-benefits that were 
monetized.

   Table 9--Estimated Reductions in Incidence of PM2.5-Related Health
                            Effects in 2016 a
------------------------------------------------------------------------
        Health effect                   Number of reduced cases
------------------------------------------------------------------------
                        Adult Premature Mortality
------------------------------------------------------------------------
    Pope et al., (2002) (age   4,200.
     >30).                     (1,200 to 7,200).
    Laden et al., (2006) (age  11,000.
     >25).                     (5,000 to 17,000).
Infant Premature Mortality     20.
 (<1 year).                    (-22 to 61).
Chronic Bronchitis...........  2,800.
                               (88 to 5,600).
Non-fatal heart attacks (age   4,700.
 >18).                         (1,200 to 8,300).
Hospital admissions--          830.
 respiratory (all ages).       (330 to 1,300).
Hospital admissions--          1,800.
 cardiovascular (age >18).     (1,200 to 2,200).
Emergency room visits for      3,100.
 asthma (age <18).             (1,600 to 4,700).
Acute bronchitis (age 8-12)..  6,300.
                               (-1,400 to 14,000).
Lower respiratory symptoms     80,000.
 (age 7-14).                   (31,000 to 130,000).
Upper respiratory symptoms     60,000.
 (asthmatics age 9-11).        (11,000 to 110,000).
Asthma exacerbation            130,000.
 (asthmatics 6-18).            (4,500 to 450,000).
Lost work days (ages 18-65)..  540,000.
                               (460,000 to 620,000).
Minor restricted-activity      3,200,000.
 days (ages 18-65).            (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.
                               ($2.6 to $100).
    7% discount rate.........  $30.
                               ($2.4 to $92).
Laden, et al., (2006) (age
 >25):
    3% discount rate.........  $87.
                               ($7.5 to $250).
    7% discount rate.........  $78.
                               ($6.8 to $230).
Infant Premature Mortality     $0.2.
 (<1 year).                    ($-0.2 to $0.8).
Chronic Bronchitis...........  $1.4.
                               ($0.1 to $6.4).
Non-fatal heart attacks (age
 >18):

[[Page 9430]]

 
    3% discount rate.........  $0.5.
                               ($0.1 to $1.3).
    7% discount rate.........  $0.4.
                               ($0.1 to $1.0).
Hospital admissions--          $0.01.
 respiratory (all ages).       ($0.01 to $0.02).
Hospital admissions--          $0.03.
 cardiovascular (age >18).     (<$0.01 to $0.05).
Emergency room visits for      <$0.01.
 asthma (age <18).
Acute bronchitis (age 8-12)..  <$0.01.
Lower respiratory symptoms     <$0.01.
 (age 7-14).
Upper respiratory symptoms     <$0.01.
 (asthmatics age 9-11).
Asthma exacerbation            <$0.01.
 (asthmatics 6-18).
Lost work days (ages 18-65)..  $0.1.
                               ($0.1 to $0.1).
Minor restricted-activity      $0.2.
 days (ages 18-65).            ($0.1 to $0.3).
------------------------------------------------------------------------
                      Monetized Health Co-Benefits
------------------------------------------------------------------------
Pope, et al., (2002):
    3% discount rate.........  $36.
                               ($2.8-$110).
    7% discount rate.........  $33.
                               ($2.5-$100).
Laden, et al., (2006):
    3% discount rate.........  $89.
                               ($7.7-$260).
    7% discount rate.........  $80.
                               ($6.9-$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. We cite two 
key empirical studies, one based on the American Cancer Society cohort 
study \374\ and the other based on the extended Six Cities cohort 
study.\375\ 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.
---------------------------------------------------------------------------

    \374\ Pope et al., 2002. ``Lung Cancer, Cardiopulmonary 
Mortality, and Long-term Exposure to Fine Particulate Air 
Pollution.'' Journal of the American Medical Association. 287:1132-
1141.
    \375\ Ladenet al., 2006. ``Reduction in Fine Particulate Air 
Pollution and Mortality.'' American Journal of Respiratory and 
Critical Care Medicine. 173:667-672.
---------------------------------------------------------------------------

    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 literature (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 for this 
rule 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 with 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 in 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

[[Page 9431]]

annual mean PM2.5 level of 10 [micro]g/m3 (the LML of the 
Ladenet al., 2006 study)or 7.5 [micro]g/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. A large fraction of the PM2.5-
related benefits occur below the level of the National Ambient Air 
Quality Standard (NAAQS) for PM2.5 at 15 [micro]g/m3, which 
was set in 2006. It is important to emphasize that NAAQS are not set at 
a level of zero risk. Instead, the NAAQS reflect the level determined 
by the Administrator to be protective of public health within an 
adequate margin of safety, taking into consideration effects on 
susceptible populations. While benefits occurring below the standard 
may be less certain than those occurring above the standard, EPA 
considers them to be legitimate components of the total benefits 
estimate.
    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 studies 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. Even though we assume that all fine particles have equivalent 
health effects, the benefit-per-ton estimates vary between directly-
emitted particles (carbonaceous and crustal particles) and 
SO2 emissions that form sulfate particles, based on the 
location of emission changes and magnitude of population exposure 
changes. Regardless, however, the assumption that all fine particles 
are equally potent in causing premature mortality adds uncertainty to 
the benefits estimate.
    b. Non-Climate Welfare Co-Benefits. Emission controls installed to 
comply with the requirements specified in 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 $1.1 billion (in 2007$). These 
visibility benefits are not included in the total co-benefits estimate 
of the final policy scenario used as a basis for this final rule. The 
distribution of emission reductions did not change substantially in the 
visibility regions studied, therefore 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; a reduction in 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 the potential public 
welfare and environmental impacts related to reductions in emissions 
required by this rule in the RIA, including reduced visibility 
impairment, reduced effects from acid deposition, reduced effects from 
nutrient enrichment, and reduced vegetation effects from ambient 
exposure to SO2 and NO2.
    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 damage 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 that 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; May 
7, 2010). The SCC Technical Support Document (SCC TSD) provides a 
complete discussion of the methods used to develop these SCC 
estimates.\376\
---------------------------------------------------------------------------

    \376\ Docket ID EPA-HQ-OAR-2009-0472-114577, Technical Support 
Document: Social Cost of Carbon for Regulatory Impact Analysis Under 
Executive Order 12866, Interagency Working Group on Social Cost of 
Carbon, with participation by Council of Economic Advisers, Council 
on Environmental Quality, Department of Agriculture, Department of 
Commerce, Department of Energy, Department of Transportation, 
Environmental Protection Agency, National Economic Council, Office 
of Energy and Climate Change, Office of Management and Budget, 
Office of Science and Technology Policy, and Department of Treasury 
(February 2010). Also available at http://epa.gov/otaq/climate/regulations.htm.
---------------------------------------------------------------------------

    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 95th percentile of 
the SCC from all three values at a 3 percent discount rate. It is 
included to represent higher-than-expected impacts from temperature 
change further out in the extremes 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 values 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 leads 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 $360 million (2007$), 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 95th percentile of the 3 percent discount rate SCC. Important 
limitations and uncertainties of the SCC approach are also described in 
the RIA.

[[Page 9432]]



  Table 11--Estimated Monetary Value (Billions 2007$) of PM2.5-Related
              Health Benefits and Climate Benefits in 2016a
------------------------------------------------------------------------
                     Effect                         Monetized benefits
------------------------------------------------------------------------
                      Monetized Health Co-Benefits
------------------------------------------------------------------------
Pope, et al., (2002):
    3% discount rate...........................                      $36
                                                             ($2.8-$110)
    7% discount rate...........................                      $33
                                                             ($2.5-$100)
Laden, et al., (2006):                           .......................
    3% discount rate...........................                      $89
                                                             ($7.7-$260)
    7% discount rate...........................                      $80
                                                             ($6.9-$240)
Climate-related Co-Benefits (3% discount rate).                    $0.36
------------------------------------------------------------------------
                       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...........................                      $90
                                                             ($8.0-$260)
    7% discount rate...........................                      $81
                                                             ($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.

    Our best estimate for the monetized total health and climate co-
benefits of this rule in 2016 at a 3 percent discount rate is between 
$37 billion and $90 billion or between $33 billion and $81 billion 
(2007$) at a 7 percent discount rate. These estimates account for the 
quantified health and climate benefits described in Table 11.

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 Executive Orders 12866 and 13563 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 2 of this preamble.
    When estimating the human health benefits and compliance costs in 
Table 2 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 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 
2 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

[[Page 9433]]

U.S.C. 3501 et seq. The Information Collection Request (ICR) document 
prepared by the EPA has been assigned EPA ICR number 2137.06.
    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.
    When a malfunction occurs, sources must report them according to 
the applicable reporting requirements of 40 CFR part 63, subpart UUUUU. 
An affirmative defense to civil penalties for exceedances of emission 
limits that are caused by malfunctions is available to a source if it 
can demonstrate that certain criteria and requirements are satisfied. 
The criteria ensure that the affirmative defense is available only 
where the event that causes an exceedance of the emission limit meets 
the narrow definition of malfunction in 40 CFR 63.2 (sudden, 
infrequent, not reasonable preventable, and not caused by poor 
maintenance and or careless operation) and where the source took 
necessary actions to minimize emissions. In addition, the source must 
meet certain notification and reporting requirements. For example, the 
source must prepare a written root cause analysis and submit a written 
report to the Administrator documenting that it has met the conditions 
and requirements for assertion of the affirmative defense.
    For this rule, EPA is adding affirmative defense to the estimate of 
burden in the ICR. To provide the public with an estimate of the 
relative magnitude of the burden associated with an assertion of the 
affirmative defense position adopted by a source, the EPA has provided 
administrative adjustments to this ICR that shows what the 
notification, recordkeeping, and reporting requirements associated with 
the assertion of the affirmative defense might entail. The EPA's 
estimate for the required notification, reports, and records, including 
the root cause analysis, associated with a single incident totals 
approximately totals $3,141, and is based on the time and effort 
required of a source to review relevant data, interview plant 
employees, and document the events surrounding a malfunction that has 
caused an exceedance of an emission limit. The estimate also includes 
time to produce and retain the record and reports for submission to 
EPA. The EPA provides this illustrative estimate of this burden, 
because these costs are only incurred if there has been a violation, 
and a source chooses to take advantage of the affirmative defense.
    The EPA provides this illustrative estimate of this burden because 
these costs are only incurred if there has been a violation and a 
source chooses to take advantage of the affirmative defense. Given the 
variety of circumstances under which malfunctions could occur, as well 
as differences among sources' operation and maintenance practices, we 
cannot reliably predict the severity and frequency of malfunction-
related excess emissions events for a particular source. It is 
important to note that the EPA has no basis currently for estimating 
the number of malfunctions that would qualify for an affirmative 
defense. Current historical records would be an inappropriate basis, as 
source owners or operators previously operated their facilities in 
recognition that they were exempt from the requirement to comply with 
emissions standards during malfunctions. Of the number of excess 
emissions events reported by source operators, only a small number 
would be expected to result from a malfunction (based on the definition 
above), and only a subset of excess emissions caused by malfunctions 
would result in the source choosing to assert the affirmative defense. 
Thus, we believe the number of instances in which source operators 
might be expected to avail themselves of the affirmative defense will 
be extremely small.
    For this reason, we estimate no more than two such occurrences for 
all sources subject to 40 CFR part 63, subpart UUUUU over the 3-year 
period covered by this ICR. We expect to gather information on such 
events in the future, and will revise this estimate as better 
information becomes available.
    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 $207.6 million. This includes 
700,296 labor hours per year at a total labor cost of $49.1 million per 
year, annualized capital costs of $81.9 million, and annual operating 
and maintenance costs of $76.5 million. This estimate includes initial 
and annual performance tests, semiannual excess emission reports, 
developing a monitoring plan, notifications, and recordkeeping. 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

[[Page 9434]]

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 the 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 Taken
    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 (2005 Action) 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 Hg from EGUs pursuant to CAA 
section 111, i.e., CAMR, May 18, 2005, 70 FR 28606). The 2005 Action 
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 
NESHAP and NSPS for EGUs.
2. Statement of Objectives and Legal Basis for Final Rules
    The MATS will protect air quality and promote public health by 
reducing emissions of 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 2005 Action reverted the status of the rule to 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. Area 
sources are any stationary sources of HAP that are not major sources.
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: 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 were not 
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. 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 SERs' input 
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 SBAR 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, recordkeeping 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. In addition, we met with representatives of 
small businesses, small rural cooperatives, and small governments a 
number of times during the regulatory development process to discuss 
their issues and concerns regarding the proposed MATS rule for EGUs.
    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

[[Page 9435]]

the CAA. The final rule includes a number of flexibilities, such as 
those related to monitoring requirements, that will lower costs and 
simplify compliance for small businesses and local governments.
    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. 
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, because they will be able to make more money serving 
larger utilities.
    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 (and final) 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.
    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 power is critical to communities, 
jobs, economic viability and electric reliability. A generating and 
transmissions electric cooperative which qualifies as a small entity 
believes the 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 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. The EPA acknowledges the comment 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.
    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 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 
across 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 that the rule contains reduced 
monitoring requirements for existing units that qualify as LEEs. 
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 and in this final 
rule. The continuous compliance alternatives are available to all 
affected sources, including small entities. As alternatives to the use 
of PM CEMS and HCl CEMS, sources are allowed to

[[Page 9436]]

conduct additional performance testing. Sorbent trap monitoring is 
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 engaged in meaningful outreach and 
consultation with small entities and therefore recommends that the EPA 
seek to revise the court-ordered 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. 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 establish GACT for smaller emitters to alleviate regulatory costs 
and operational difficulties. A commenter believes it is likely that 
different numerical or work practice standards are appropriate for area 
sources of HAP.
    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, notwithstanding 
the constraints of 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, addresses the statutorily required elements 
of an IRFA, such as the economic impact of the proposed rule on small 
entities and the Panel's findings.
    The EPA disagrees with the comment that recommendations made by the 
SERs were not considered or discussed in the proposed rulemaking such 
as recommendations regarding subcategorization and separate GACT 
standards for area sources. The preamble to the proposed standards 
includes a 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).
    The EPA also disagrees with the suggestion that the Agency 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. The EPA and Plaintiffs stipulated to a 30-day extension 
consistent with the modification provisions of the Consent Decree and 
the rule must be signed no later than December 16, 2011. If plaintiffs 
in the American Nurses litigation objected to an additional extension 
request, which we believe would have been likely, 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:

[[Page 9437]]

    (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 82 potentially affected small entities that are 
affiliated with 102 EGUs.
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 $106 million in 2015 (2007$).
    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 
82 small entities identified, The EPA's analysis shows 40 entities may 
experience compliance costs greater than 1 percent of base generation 
revenues in 2015, and 35 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 35 of the 82 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 significant economic impact on a substantial number of small 
entities (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 $175 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 varies 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

[[Page 9438]]

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 is 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. Descriptions of the work practice requirements 
for startup and shutdown, as well as organic HAP and limited-use liquid 
oil-fired EGUs, 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 consistent with the 
statute to adopt the proposed subcategories, the EPA maintained the 
existing subcategories and split the ``liquid oil-fired units'' 
subcategory into three subcategories--continental, non-continental 
units, and limited-use 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.
    e. Alternatives not adopted. The EPA did not 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 consideration of 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 document.
    The EPA determined 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 determined 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 UMRA of 1995, Public Law 104-4, establishes 
requirements for federal agencies to assess the effects of their 
regulatory actions on state, local, and tribal governments and the 
private sector. Under UMRA section 202, we generally must prepare a 
written statement, including a cost-benefit analysis, for proposed and 
final rules with ``Federal mandates'' that may result in expenditures 
to state, local, and tribal governments, in the aggregate, or to the 
private sector, of $100 million or more in any 1 year. Before 
promulgating a rule for which a written statement is needed, UMRA 
section 205 generally requires us 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. The provisions of UMRA section 205 do not apply 
when they are inconsistent with applicable law. Moreover, UMRA section 
205 allows us to adopt an alternative other than the least costly, most 
cost-effective or least burdensome alternative if the Administrator 
publishes with the final rule an explanation why that alternative was 
not adopted. Before we establish any regulatory requirements that may 
significantly or uniquely affect small governments, including tribal 
governments, we must develop a small government agency plan under UMRA 
section 203. The plan must provide for notifying potentially affected 
small governments, enabling officials of affected small governments to 
have meaningful and timely input in the development of regulatory 
proposals with significant federal intergovernmental mandates, and 
informing, educating, and advising small governments on compliance with 
the regulatory requirements.
    We have determined that 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 
1 year. Accordingly, we have prepared a written statement entitled 
``Unfunded Mandates Reform Act Analysis'' under

[[Page 9439]]

UMRA section 202 that is within the RIA and which is summarized below.
1. Statutory Authority
    As discussed elsewhere in this preamble, the statutory authority 
for this rulemaking is CAA section 112. Title III of the CAA Amendments 
was enacted to reduce nationwide air toxic emissions. CAA section 
112(b) lists the 188 chemicals, compounds, or groups of chemicals 
deemed by Congress to be HAP. These toxic air pollutants are to be 
regulated by NESHAP.
    CAA section 112(d) directs us to develop NESHAP which require 
existing and new major sources to control emissions of HAP using MACT-
based standards. This NESHAP applies to all coal- and oil-fired EGUs.
    In compliance with UMRA section 205(a), we identified and 
considered a reasonable number of regulatory alternatives. Additional 
information on the costs and environmental impacts of these regulatory 
alternatives were presented in the RIA for the rulemaking.
    The regulatory alternative upon which this rule is based represents 
the MACT floor for all regulated pollutants for all but one EGU 
subcategory for all but one regulated pollutant for that subcategory. 
These MACT floor-based standards represent the least costly and least 
burdensome alternative. Beyond-the-floor emission limits for Hg are for 
existing coal-fired EGUs in the subcategory for low rank virgin coal 
EGUs.
2. Social Costs and Benefits
    The RIA prepared for this rule including the Agency's assessment of 
costs and benefits is in the docket.
    It is estimated that HAP would be reduced by thousands of tons in 
2015, relative to the base case, including reductions in HCl, HF, 
metallic HAP (including Hg), and several other organic HAP from EGUs. 
Studies have determined a relationship between exposure to certain of 
these HAP and the onset of cancer; however, the Agency is unable to 
provide a monetized estimate of the HAP benefits at this time. In 
addition, significant reductions in PM2.5 and SO2 
will occur, including approximately 53 thousand tons of 
PM2.5 and over 1 million tons of SO2. These 
reductions will occur by 2016 and are expected to continue throughout 
the life of the affected sources. The major health effect associated 
with reducing PM2.5 and PM2.5 precursors (such as 
SO2) is a reduction in premature mortality. Other health 
effects associated with PM2.5 emission reductions include 
avoiding cases of chronic bronchitis, heart attacks, asthma attacks, 
and work-lost days (i.e., days when employees are unable to work). 
Although we are unable to monetize the benefits associated with the HAP 
emissions reductions other than for Hg or all benefits associated with 
Hg reductions, we are able to monetize the benefits associated with the 
PM2.5 and SO2 emissions reductions. For 
SO2 and PM2.5, we estimated the benefits 
associated with health effects of PM but were unable to quantify all 
categories of benefits (particularly those associated with ecosystem 
and visibility effects). Our estimates of the monetized benefits in 
2016 associated with the implementation of the final rule range from 
$37 billion to $90 billion (2007 dollars) when using a 3 percent 
discount rate or from $33 billion to $81 billion (2007 dollars) when 
using a 7 percent discount rate). Our estimate of costs is $9.6 billion 
(2007 dollars). For more detailed information on the benefits and costs 
estimated for this rulemaking, refer to the RIA in the docket.
3. Future and Disproportionate Costs
    The UMRA requires that we estimate, where accurate estimation is 
reasonably feasible, future compliance costs imposed by this rule and 
any disproportionate budgetary effects. Our estimates of the future 
compliance costs of this rule are discussed previously in this 
preamble.
    The EPA assessed the economic and financial impacts of the rule on 
government-owned entities 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 base revenues. The EPA projects that 42 government 
entities will have compliance costs greater than 1 percent of base 
generation revenue in 2016, and 32 may experience compliance costs 
greater than 3 percent of base revenues. Overall, 6 units owned by 
government entities are expected to retire. The most significant 
components of incremental costs to these entities are the increased 
capital and operating costs, followed by changes in electricity 
revenues. For more details on these results and the methodology behind 
their estimation, see the results included in chapter 7 of the RIA.
4. Effects on the National Economy
    The UMRA requires that we estimate the effect of this rule on the 
national economy. To the extent feasible, we must estimate the effect 
on productivity, economic growth, full employment, creation of 
productive jobs, and international competitiveness of the U.S. goods 
and services, if we determine that accurate estimates are reasonably 
feasible and that such effect is relevant and material.
    The nationwide economic impact of this rule is presented in the RIA 
in the docket. This analysis provides estimates of the effect of this 
rule on some of the categories mentioned above.
    The results of the economic impact analysis are summarized 
previously in this preamble. The results show that, relative to 
baseline, there will be an average 3.1 percent increase in electricity 
price on average nationwide in 2016, with the range of increases from 
1.3 percent to 6.3 percent in regions throughout the U.S., and a less 
than 1 percent increase in natural gas price nationwide in 2016. The 
roughly 3 percent incremental price effect of this rule is small 
relative to the changes observed in the absolute levels of electricity 
prices over the last 50 years, which have ranged from as much as 23 
percent lower (in 1969) to as much as 23 percent higher (in 1982) than 
prices observed in 2010.\377\ Power generation from coal-fired plants 
will fall by about 2 percent nationwide in 2016. No region of the U.S. 
is expected to experience a double-digit increase in retail electricity 
prices in 2015 or in any year later than that, according to the 
Agency's analysis, as a result of this rule. To put the electricity 
price effects in context, the roughly 3 percent incremental increase in 
aggregate end-user electricity prices projected to occur over the next 
4 years is about the same as the 3 percent absolute average change in 
total end-user electricity prices observed on an annual basis.\378\ 
Furthermore, the roughly 3 percent incremental price effect of this 
rule is small relative to the changes observed in the absolute levels 
of electricity prices over the last 50 years, which have ranged from as 
much as 23 percent lower (in 1969) to as much as 23 percent higher (in 
1982) than prices observed in 2010.\379\ Even with this rule in effect, 
electricity prices are projected to be lower in 2015 and 2020 than they 
were in 2010.\380\
---------------------------------------------------------------------------

    \377\ EIA Annual Energy Outlook 2010 annual total electricity 
prices from 1960 to 2010, Table 8-10.
    \378\ EIA Annual Energy Outlook 2010 annual total electricity 
prices from 1960 t0 2010, Table 8-10.
    \379\ Ibid.
    \380\ Ibid., EIA AEO 2010, Table-10 for price levels; and 
Chapterr 3 of the RIA for electricity price differential.
---------------------------------------------------------------------------

5. Consultation With Government
    The UMRA requires that we describe the extent of the Agency's prior 
consultation with affected state, local,

[[Page 9440]]

and tribal officials, summarize the officials' comments or concerns, 
and summarize our response to those comments or concerns. In addition, 
UMRA section 203 requires that we develop a plan for informing and 
advising small governments that may be significantly or uniquely 
impacted by a regulatory action. Consistent with the intergovernmental 
consultation provisions of UMRA section 204, the EPA initiated 
consultations with governmental entities affected by this rule. The EPA 
invited the following 10 national organizations representing state and 
local elected officials to a meeting held on October 27, 2010, in 
Washington, DC: (1) National Governors Association; (2) National 
Conference of State Legislatures, (3) Council of State Governments, (4) 
National League of Cities, (5) U.S. Conference of Mayors, (6) National 
Association of Counties, (7) International City/County Management 
Association, (8) National Association of Towns and Townships, (9) 
County Executives of America, and (10) Environmental Council of States. 
These 10 organizations of elected state and local officials have been 
identified by the EPA as the ``Big 10'' organizations appropriate to 
contact for purpose of consultation with elected officials. The 
purposes of the consultation were to provide general background on the 
rule, answer questions, and solicit input from state/local governments. 
During the meeting, officials asked clarifying questions regarding CAA 
section 112 requirements and central decision points presented by the 
EPA (e.g., use of surrogate pollutants to address HAP, 
subcategorization of source category, assessment of emissions 
variability). They also expressed uncertainty with regard to how 
utility boilers owned/operated by state and local entities would be 
impacted, as well as with regard to the potential burden associated 
with implementing the rule on state and local entities (i.e., burden to 
re-permit affected EGUs or update existing permits). Officials 
requested, and the EPA provided, addresses associated with the 112 
state and local governments estimated to be potentially impacted by the 
rule. The EPA has not received additional questions or requests from 
state or local officials.
    Consistent with UMRA section 205, the EPA has identified and 
considered a reasonable number of regulatory alternatives. Because the 
potential existed for a significant impact for substantial number of 
small entities, the EPA convened a SBAR Panel to obtain advice and 
recommendation of representatives of the small entities that 
potentially would be subject to the requirements of the rule. As part 
of that process, the EPA considered several options, which are 
discussed previously in this preamble. Those options included 
establishing emission limits, establishing work practice standards, 
establishing subcategories, and consideration of monitoring options. 
The regulatory alternative selected is a combination of the options 
considered and includes provisions regarding a number of the 
recommendations resulting from the SBAR Panel process as described 
below (see the Regulatory Flexibility Act discussion in this section of 
the preamble for more detail).

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 $294 million in annual direct compliance costs on an 
estimated 96 state or local governments. Specifically, we estimate that 
there are 80 municipalities, 5 states, and 11 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. In the 
final rule, EPA has provided flexibilities that will lower compliance 
costs for these entities. The EPA also recognizes that municipalities 
may need a longer compliance timeframe because of required approval 
processes.

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. The EPA offered consultation with tribal officials early 
in the regulation development process to permit them an opportunity to 
have meaningful and timely input. Consultation letters were sent to 584 
tribal leaders and provided information regarding the EPA's development 
of this rule and offered consultation. At the request of the tribes, 
three consultation meetings were held: 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, 
and Fond du Lac Band of Chippewa; January 5, 2011, with the Forest 
County Potawatomi, and a representative from the National Tribal Air 
Association (NTAA). 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 in 
Indian country. Specifically, 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

[[Page 9441]]

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 related to how the Agency would consider variability in setting 
the standards, and 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 MACT 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 NTAA; 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 (i.e., 
assumptions about reduced mining if NGS were to retire one or more 
units), and the impacts on employment of tribal members at both the NGS 
and the mine. More specific comments can be found in the docket.
    The EPA will continue to work with these and other potentially 
affected tribes as this final rule is implemented.

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 is particularly 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. We also estimate substantial health improvements 
for children in the form of 130,000 fewer asthma attacks, 3,100 fewer 
emergency room visits due to asthma, 6,300 fewer cases of acute 
bronchitis, and approximately 140,000 fewer cases of upper and lower 
respiratory illness.

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 3.1 percent price increase for electricity nationwide 
in 2016 and a less than 2 percent percentage fall in coal-fired power 
production as a result of this rule. The EPA projects that electric 
power sector-delivered natural gas prices will increase by about 0.6 
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 (Pub. L. 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 National Standards 
Institute (ANSI)/American Society of Mechanical Engineers (ASME) PTC 
19-10-1981, ``Flue and Exhaust Gas Analyses [part 10, Instruments and 
Apparatus]'' is cited in the final rule for its manual method for 
measuring the O2, CO2, and CO content of exhaust 
gas. This part of ANSI/ASME PTC 19-10-1981 is an acceptable alternative 
to Method 3B.
    The voluntary consensus standard ASTM D6348-03 (Reapproved 2010), 
``Standard Test Method for 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 D6348-03, 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

[[Page 9442]]

equation: Reported Result = (Measured Concentration in the Stack x 
100)/% R.
    The voluntary consensus standard ASTM D6784-02, ``Standard Test 
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 Hg 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. In addition to the voluntary consensus standards the EPA used in 
the final rule, the search for emissions measurement procedures 
identified 16 other voluntary consensus standards. The EPA determined 
that 14 of these 16 standards identified for measuring emissions of the 
HAP or other pollutants subject to emission standards in the final rule 
were impractical alternatives to EPA test methods for the purposes of 
this final rule. Therefore, the EPA did not adopt these standards for 
this purpose. The reasons for this determination for the 14 methods are 
discussed below, and the remaining 2 methods are discussed later in 
this section.
    The voluntary consensus standard ASTM D3154-00, ``Standard Method 
for Average Velocity in a Duct (Pitot Tube Method),'' is impractical as 
an alternative to EPA Methods 1, 2, 3B, and 4 for the purposes of this 
rulemaking because the standard appears to lack in quality control and 
quality assurance requirements. Specifically, ASTM D3154-00 does not 
include the following: (1) proof that openings of standard pitot tube 
have not plugged during the test; (2) if differential pressure gauges 
other than inclined manometers (e.g., magnehelic gauges) are used, 
their calibration must be checked after each test series; and (3) the 
frequency and validity range for calibration of the temperature 
sensors.
    The voluntary consensus standard ASTM D3464-96 (Reapproved 2001), 
``Standard Test Method Average Velocity in a Duct Using a Thermal 
Anemometer,'' is impractical as an alternative to EPA Method 2 for the 
purposes of this rule primarily because applicability specifications 
are not clearly defined, e.g., range of gas composition, temperature 
limits. Also, the lack of supporting quality assurance data for the 
calibration procedures and specifications, and certain variability 
issues that are not adequately addressed by the standard limit the 
EPA's ability to make a definitive comparison of the method in these 
areas.
    The voluntary consensus standard ISO 10780:1994, ``Stationary 
Source Emissions--Measurement of Velocity and Volume Flowrate of Gas 
Streams in Ducts,'' is impractical as an alternative to EPA Method 2 in 
this rule. The standard recommends the use of an L-shaped pitot, which 
historically has not been recommended by the EPA. The EPA specifies the 
S-type design which has large openings that are less likely to plug up 
with dust.
    The voluntary consensus standard, CAN/CSA Z223.2-M86 (1999), 
``Method for the Continuous Measurement of Oxygen, Carbon Dioxide, 
Carbon Monoxide, Sulphur Dioxide, and Oxides of Nitrogen in Enclosed 
Combustion Flue Gas Streams,'' is unacceptable as a substitute for EPA 
Method 3A because it does not include quantitative specifications for 
measurement system performance, most notably the calibration procedures 
and instrument performance characteristics. The instrument performance 
characteristics that are provided are non-mandatory and also do not 
provide the same level of quality assurance as the EPA methods. For 
example, the zero and span/calibration drift is only checked weekly, 
whereas the EPA methods require drift checks after each run.
    Two very similar voluntary consensus standards, ASTM D5835-95 
(Reapproved 2001), ``Standard Practice for Sampling Stationary Source 
Emissions for Automated Determination of Gas Concentration,'' and ISO 
10396:1993, ``Stationary Source Emissions: Sampling for the Automated 
Determination of Gas Concentrations,'' are impractical alternatives to 
EPA Method 3A for the purposes of this final rule because they lack in 
detail and quality assurance/quality control requirements. 
Specifically, these two standards do not include the following: (1) 
Sensitivity of the method; (2) acceptable levels of analyzer 
calibration error; (3) acceptable levels of sampling system bias; (4) 
zero drift and calibration drift limits, time span, and required 
testing frequency; (5) a method to test the interference response of 
the analyzer; (6) procedures to determine the minimum sampling time per 
run and minimum measurement time; and (7) specifications for data 
recorders, in terms of resolution (all types) and recording intervals 
(digital and analog recorders, only).
    The voluntary consensus standard ISO 12039:2001, ``Stationary 
Source Emissions--Determination of Carbon Monoxide, Carbon Dioxide, and 
Oxygen--Automated Methods,'' is not acceptable as an alternative to EPA 
Method 3A. This ISO standard is similar to EPA Method 3A, but is 
missing some key features. In terms of sampling, the hardware required 
by ISO 12039:2001 does not include a 3-way calibration valve assembly 
or equivalent to block the sample gas flow while calibration gases are 
introduced. In its calibration procedures, ISO 12039:2001 only 
specifies a two-point calibration while EPA Method 3A specifies a 
three-point calibration. Also, ISO 12039:2001 does not specify 
performance criteria for calibration error, calibration drift, or 
sampling system bias tests as in the EPA method, although checks of 
these quality control features are required by the ISO standard.
    The voluntary consensus standard ASTM D6522-00, ``Standard Test 
Method for the Determination of Nitrogen Oxides, Carbon Monoxide, and 
Oxygen Concentrations in Emissions from Natural Gas-Fired Reciprocating 
Engines, Combustion Turbines, Boilers and Process Heaters Using 
Portable Analyzers'' is not an acceptable alternative to EPA Method 3A 
for measuring CO and O2 concentrations for this final rule 
as the method is designed for application to sources firing natural 
gas.
    The voluntary consensus standard ASME PTC-38-80 R85 (1985), 
``Determination of the Concentration of Particulate Matter in Gas 
Streams,'' is not acceptable as an alternative for EPA Method 5 because 
ASTM PTC-38-80 is not specific about equipment requirements, and 
instead presents the options available and the pros and cons of each 
option. The key specific differences between ASME PTC-38-80 and the EPA 
methods are that the ASME standard: (1) Allows in-stack filter 
placement as compared to the out-of-stack filter placement in EPA 
Methods 5 and 17; (2) allows many different types of nozzles, pitots, 
and filtering equipment; (3) does not specify a filter weighing 
protocol or a minimum allowable filter weight fluctuation as in the EPA 
methods; and (4) allows filter paper to be only 99 percent efficient, 
as compared to the 99.95 percent efficiency required by the EPA 
methods.
    The voluntary consensus standard ASTM D3685/D3685M-98, ``Test 
Methods for Sampling and Determination of Particulate Matter in Stack 
Gases,'' is similar to EPA Methods 5 and 17, but is lacking in the 
following areas that are needed to produce quality, representative 
particulate data: (1) Requirement that the filter holder temperature 
should be between 120[deg]C and 134[deg]C, and not just ``above the 
acid dew-point''; (2) detailed specifications

[[Page 9443]]

for measuring and monitoring the filter holder temperature during 
sampling; (3) procedures similar to EPA Methods 1, 2, 3, and 4, that 
are required by EPA Method 5; (4) technical guidance for performing the 
Method 5 sampling procedures, e.g., maintaining and monitoring sampling 
train operating temperatures, specific leak check guidelines and 
procedures, and use of reagent blanks for determining and subtracting 
background contamination; and (5) detailed equipment and/or operational 
requirements, e.g., component exchange leak checks, use of glass 
cyclones for heavy particulate loading and/or water droplets, operating 
under a negative stack pressure, exchanging particulate loaded filters, 
sampling preparation and implementation guidance, sample recovery 
guidance, data reduction guidance, and particulate sample calculations 
input.
    The voluntary consensus standard ISO 9096:1992, ``Determination of 
Concentration and Mass Flow Rate of Particulate Matter in Gas Carrying 
Ducts--Manual Gravimetric Method,'' is not acceptable as an alternative 
for EPA Method 5. Although sections of ISO 9096 incorporate EPA Methods 
1, 2, and 5 to some degree, this ISO standard is not equivalent to EPA 
Method 5 for collection of PM. The standard ISO 9096 does not provide 
applicable technical guidance for performing many of the integral 
procedures specified in Methods 1, 2, and 5. Major performance and 
operational details are lacking or nonexistent, and detailed quality 
assurance/quality control guidance for the sampling operations required 
to produce quality, representative particulate data (e.g., guidance for 
maintaining and monitoring train operating temperatures, specific leak 
check guidelines and procedures, and sample preparation and recovery 
procedures) are not provided by the standard, as in EPA Method 5. Also, 
details of equipment and/or operational requirements, such as those 
specified in EPA Method 5, are not included in the ISO standard, e.g., 
stack gas moisture measurements, data reduction guidance, and 
particulate sample calculations.
    The voluntary consensus standard CAN/CSA Z223.1-M1977, ``Method for 
the Determination of Particulate Mass Flows in Enclosed Gas Streams,'' 
is not acceptable as an alternative for EPA Method 5. Detailed 
technical procedures and quality control measures that are required in 
EPA Methods 1, 2, 3, and 4 are not included in CAN/CSA Z223.1. Second, 
CAN/CSA Z223.1 does not include the EPA Method 5 filter weighing 
requirement to repeat weighing every 6 hours until a constant weight is 
achieved. Third, EPA Method 5 requires the filter weight to be reported 
to the nearest 0.1 milligram (mg), while CAN/CSA Z223.1 requires 
reporting only to the nearest 0.5 mg. Also, CAN/CSA Z223.1 allows the 
use of a standard pitot for velocity measurement when plugging of the 
tube opening is not expected to be a problem. The EPA Method 5 requires 
an S-shaped pitot.
    The voluntary consensus standard EN 1911-1,2,3 (1998), ``Stationary 
Source Emissions-Manual Method of Determination of HCl-Part 1: Sampling 
of Gases Ratified European Text-Part 2: Gaseous Compounds Absorption 
Ratified European Text-Part 3: Adsorption Solutions Analysis and 
Calculation Ratified European Text,'' is impractical as an alternative 
to EPA Methods 26 and 26A. Part 3 of this standard cannot be considered 
equivalent to EPA Method 26 or 26A because the sample absorbing 
solution (water) would be expected to capture both HCl and chlorine 
gas, if present, without the ability to distinguish between the two. 
The EPA Methods 26 and 26A use an acidified absorbing solution to first 
separate HCl and chlorine gas so that they can be selectively absorbed, 
analyzed, and reported separately. In addition, in EN 1911 the 
absorption efficiency for chlorine gas would be expected to vary as the 
pH of the water changed during sampling.
    The voluntary consensus standard EN 13211 (1998), is not acceptable 
as an alternative to the Hg portion of EPA Method 29 primarily because 
it is not validated for use with impingers, as in the EPA method, 
although the method describes procedures for the use of impingers. This 
European standard is validated for the use of fritted bubblers only and 
requires the use of a side (split) stream arrangement for isokinetic 
sampling because of the low sampling rate of the bubblers (up to 3 
liters per minute, maximum). Also, only two bubblers (or impingers) are 
required by EN 13211, whereas EPA Method 29 require the use of six 
impingers. In addition, EN 13211 does not include many of the quality 
control procedures of EPA Method 29, especially for the use and 
calibration of temperature sensors and controllers, sampling train 
assembly and disassembly, and filter weighing.
    Two of the 16 voluntary consensus standards identified in this 
search were not available at the time the review was conducted for the 
purposes of the final rule because they are under development by a 
voluntary consensus body: ASME/BSR MFC 13M, ``Flow Measurement by 
Velocity Traverse,'' for EPA Method 2 (and possibly 1); and ASME/BSR 
MFC 12M, ``Flow in Closed Conduits Using Multiport Averaging Pitot 
Primary Flowmeters,'' for EPA Method 2.
    Finally, in addition to the three voluntary consensus standards 
identified as acceptable alternatives to EPA methods required in the 
final rule, the EPA is also specifying four voluntary consensus 
standards in the rule for use in sampling and analysis of liquid oil 
samples for moisture content. These standards are: ASTM D95-05 
(Reapproved 2010), ``Standard Test Method for Water in Petroleum 
Products and Bituminous Materials by Distillation,'' ASTM D4006-11, 
``Standard Test Method for Water in Crude Oil by Distillation,'' ASTM 
D4177-95 (Reapproved 2010), ``Standard Practice for Automatic Sampling 
of Petroleum and Petroleum Products,'' and ASTM D4057-06 (Reapproved 
2011), ``Standard Practice for Manual Sampling of Petroleum and 
Petroleum Products.''
    Table 5, section 4.1.1.5 of appendix A, and section 3.1.2 of 
appendix B to subpart UUUUU, 40 CFR part 63, list the EPA testing 
methods included in the final rule. Under section 63.7(f) and section 
63.8(f) of subpart A of the General Provisions, a source may apply to 
the EPA for permission to use alternative test methods or alternative 
monitoring requirements in place of any of the EPA testing methods, 
performance specifications, or procedures specified.

J. Executive Order 12898: Federal Actions To Address Environmental 
Justice in Minority Populations and Low-Income Populations

    Executive Order 12898 (59 FR 7629; February 16, 1994) establishes 
federal executive policy on environmental justice (EJ). Its main 
provision directs federal agencies, to the greatest extent practicable 
and permitted by law, to make EJ part of their mission by identifying 
and addressing, as appropriate, disproportionately high and adverse 
human health or environmental effects of their programs, policies, and 
activities on minority populations and low-income populations in the 
U.S.
    The EPA has determined that this final rule will not have 
disproportionately high and adverse human health or environmental 
effects on minority, low income, and indigenous populations because it 
increases the level of environmental protection for all affected 
populations without having any disproportionately

[[Page 9444]]

high and adverse human health or environmental effects on any 
population, including any minority, low income, and indigenous 
populations.
    This final rule establishes national emission standards for new and 
existing EGUs that combust coal and oil. The EPA estimates that there 
are approximately 1,400 units located at 600 facilities covered by this 
final rule.
    This final rule will reduce emissions of all the listed HAP that 
come from EGUs. This includes metals (Hg, As, Be, Cd, Cr, Pb, Mn, Ni, 
and Se), organics (POM, acetaldehyde, acrolein, benzene, dioxins, 
ethylene dichloride, formaldehyde, and PCB), and acid gases (HCl and 
HF). At sufficient levels of exposure, these pollutants can cause a 
range of health effects including cancer; irritation of the lungs, 
skin, and mucous membranes; effects on the central nervous system such 
as memory and IQ loss and learning disabilities; damage to the kidneys; 
and other acute health disorders.
    The final rule will also result in substantial reductions of 
criteria pollutants such as CO, PM, and SO2. Sulfur dioxide 
is a precursor pollutant that is often transformed into fine PM 
(PM2.5) in the atmosphere. Reducing direct emissions of 
PM2.5 and SO2 will, as a result, reduce 
concentrations of PM2.5 in the atmosphere. These reductions 
in PM2.5 will provide large health benefits, such as 
reducing the risk of premature mortality for adults, chronic and acute 
bronchitis, childhood asthma attacks, and hospitalizations for other 
respiratory and cardiovascular diseases. (For more details on the 
health effects of metals, organics, and PM2.5, please refer 
to the RIA contained in the docket for this rulemaking.) This final 
rule will also have a small effect on electricity and natural gas 
prices but has the potential to affect the cost structure of the 
utility industry and could lead to shifts in how and where electricity 
is generated.
    This final rule is one of a group of regulatory actions that the 
EPA has taken and will take over the next several years to respond to 
statutory and judicial mandates that will reduce exposure to HAP and 
PM2.5, as well as to other pollutants, from EGUs and other 
sources. In addition, the EPA will pursue energy efficiency 
improvements throughout the economy, along with other federal agencies, 
states and other groups. This will contribute to additional 
environmental and public health improvements while lowering the costs 
of realizing those improvements. Together, these rules and actions will 
have substantial and long-term effects on both the U.S. power industry 
and on communities currently breathing dirty air. Therefore, we 
anticipate significant interest in many, if not most, of these actions 
from EJ communities, among many others.
1. Key EJ Aspects of the Rule
    This is an air toxics rule; therefore, it does not permit emissions 
trading among sources. Instead, this final rule will place a limit on 
the rates of Hg and other HAP emitted from each affected EGU. As a 
result, emissions of Hg and other HAP such as HCl will be substantially 
reduced in the vast majority of states. In some states, however, there 
may be small increases in Hg and other HAP emissions due to shifts in 
electricity generation from EGUs with higher emission rates to EGUs 
with already low emission rates. Hydrogen chloride emissions are 
projected to increase at a small number of sources but that does not 
lead to any increased emissions at the state level.
    The primary risk analysis to support the finding that this final 
rule is both appropriate and necessary includes an analysis of the 
effects of Hg from EGUs on people who rely on freshwater fish they 
catch as a regular and frequent part of their diet. These groups are 
characterized as subsistence level fishing populations or fishers. A 
significant portion of the data in this analysis came from published 
studies of EJ communities where people frequently consume locally-
caught freshwater fish. These communities included: (1) White and black 
populations (including female and poor strata) surveyed in South 
Carolina; (2) Hispanic, Vietnamese and Laotian populations surveyed in 
California; and (3) Great Lakes tribal populations (Chippewa and 
Ojibwe) active on ceded territories around the Great Lakes. These data 
were used to help estimate risks to similar populations beyond the 
areas where the study data were collected. For example, while the 
Vietnamese and Laotian survey data were collected in California, given 
the ethnic (heritage) nature of these high fish consumption rates, we 
assumed that they could also be associated with members of these ethnic 
groups living elsewhere in the U.S. Therefore, the high-end consumption 
rates referenced in the California study for these ethnic groups were 
used to model risk at watersheds elsewhere in the U.S. As a result of 
this approach, the specific fish consumption patterns of several 
different EJ groups are fundamental to the EPA's assessment of both the 
underlying risks that make this final rule appropriate and necessary, 
and of the analysis of the benefits of reducing exposure to Hg and the 
other HAP.
    The EPA's full analysis of risks from consumption of Hg-
contaminated fish is contained in the RIA for this rule. The effects of 
this final rule on the health risks from Hg and other HAP are presented 
in the preamble and in the RIA for this rule.
2. Potential Environmental and Public Health Impacts to Minority, Low 
Income, or Tribal Populations
    The EPA has conducted several analyses that provide additional 
insight on the potential effects of this rule on EJ communities. These 
include: (1) The socio-economic distribution of people living close to 
affected EGUs who may be exposed to pollution from these sources; and 
(2) an analysis of the distribution of health effects expected from the 
reductions in PM2.5 that will result from implementation of 
this final rule (co-benefits).
    a. Socio-Economic Distribution. As part of the analysis for this 
final rule, the EPA reviewed the aggregate demographic makeup of the 
communities near EGUs covered by this final rule. Although this 
analysis gives some indication of populations that may be exposed to 
levels of pollution that cause concern, it does not identify the 
demographic characteristics of the most highly affected individuals or 
communities. Electric generating units usually have very tall emission 
stacks; this tends to disperse the pollutants emitted from these stacks 
fairly far from the source. In addition, several of the pollutants 
emitted by these sources, such as a common form of Hg and 
SO2, are known to travel long distances and contribute to 
adverse impacts on both the environment and human health hundreds or 
even thousands of miles from where they were emitted (in the case of 
elemental Hg, globally).
    The proximity-to-the-source review is included in the analysis for 
this final rule because some EGUs emit enough HAP such as Ni or Cr(VI) 
to cause elevated lifetime cancer risks greater than 1 in a million in 
nearby communities. In addition, the EPA's analysis indicates that 
there are localized areas with potential for elevated levels of Hg 
deposition around most U.S. EGUs.\381\
---------------------------------------------------------------------------

    \381\ See Excess Local Deposition TSD for more detail.
---------------------------------------------------------------------------

    The analysis of demographic data used proximity-to-the-source as a 
surrogate for exposure to identify those populations considered to be 
living near affected sources, such that they have notable exposures to 
current HAP

[[Page 9445]]

emissions from these sources. The demographic data for this analysis 
were extracted from the 2000 census data which were provided to the EPA 
by the U.S. Census Bureau. Distributions by race are based on 
demographic information at the census block level, and all other 
demographic groups are based on the extrapolation of census block group 
level data to the census block level. The socio-demographic parameters 
used in the analysis included the following categories: Racial (White, 
African American, Native American, Other or Multiracial, and All Other 
Races); Ethnicity (Hispanic); and Other (Number of people below the 
poverty line, Number of people with ages between 0 and 18, Number of 
people greater than or equal to 65, Number of people with no high 
school diploma).
    In determining the aggregate demographic makeup of the communities 
near affected sources, the EPA focused on those census blocks within 
three miles of affected sources and determined the demographic 
composition (e.g., race, income, etc.) of these census blocks and 
compared them to the corresponding compositions nationally. The radius 
of 3 miles (or approximately 5 kilometers) is consistent with other 
demographic analyses focused on areas around potential sources. In 
addition, air quality modeling experience has shown that the area 
within three miles of an individual source of emissions can generally 
be considered the area with the highest ambient air levels of the 
primary pollutants being emitted for most sources, both in absolute 
terms and relative to the contribution of other sources (assuming there 
are other sources in the area, as is typical in urban areas). Although 
facility processes and fugitive emissions may have more localized 
impacts, the EPA acknowledges that because of various stack heights 
there is the potential for dispersion beyond 3 miles. To the extent 
that any minority, low income, and indigenous subpopulation is 
disproportionately impacted by the current emissions as a result of the 
proximity of their homes to these sources, that subpopulation also 
stands to see increased environmental and health benefit from the 
emissions reductions called for by this rule. The results of the EPA's 
demographic analysis for affected sources are shown in the following 
table: 382 383

                             Table 12--Comparative Summary of the Demographics Within 5 KM (3 Miles) of the Affected Sources
                                                              [Population in millions] 382
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                              African         Native         Other and                                     Below poverty
                                               White         American        American       multiracial      Hispanic      Minority 383        line
--------------------------------------------------------------------------------------------------------------------------------------------------------
Near Source Total (3 mi)................            8.78            2.51            0.10            2.52            2.86            5.13            2.43
% of Near Source Total..................           63              18               1              18              21              37              17
National Total..........................          215              35               2.49           33.3            39.1            70.8            37.1
% of National Total.....................           75              12               1              12              14              25              13
--------------------------------------------------------------------------------------------------------------------------------------------------------
\382\ Racial and ethnic categories overlap and cannot be summed.
\383\ The ``Minority'' population is the overall population (in the first row) minus white population (in the second row).

    The data indicate that coal-fired EGUs are located in areas where 
the minority share of the population living within a three mile buffer 
is higher than the national average by 12 percentage points or 48 
percent. For these same areas, the percent of the population below the 
poverty line is also higher than the national average by 4 percentage 
points or 31 percent. These results are presented in more detail in the 
``Review of Proximity Analysis,'' February 2011, a copy of which is 
available in the docket.
    b. PM2.5 (Co-Benefits) Analysis. As mentioned above, 
many of the steps EGUs will take to reduce their emissions of air 
toxics as required by this final rule will also reduce emissions of PM 
and SO2. As a result, this final rule will reduce 
concentrations of PM2.5 in the atmosphere. Exposure to 
PM2.5 can cause or contribute to adverse health effects, 
such as asthma and heart disease, that significantly affect many 
minority, low-income, and tribal individuals and their communities. 
Fine PM (PM2.5) is particularly (but not exclusively) 
harmful to children, the elderly, and people with existing heart and 
lung diseases, including asthma. Exposure can cause premature death and 
trigger heart attacks, asthma attacks in children and adults with 
asthma, chronic and acute bronchitis, and emergency room visits and 
hospitalizations, as well as milder illnesses that keep children home 
from school and adults home from work. Missing work due to illness or 
the illness of a child is a particular problem for people who have jobs 
that do not provide paid sick days. Low-wage employees also risk losing 
their jobs if they are absent too often, even if it is due to their own 
illness or the illness of a child or other relative. Finally, many 
individuals in these communities lack access to high quality health 
care to treat these types of illnesses. Due to all these factors, many 
minority and low-income communities are particularly susceptible to the 
health effects of PM2.5 and receive a variety of benefits 
from reducing it.
    We estimate that in 2016 the annual PM-related benefits of the 
final rule for adults include approximately 4,200 to 11,000 fewer 
premature mortalities, 2,900 fewer cases of chronic bronchitis, 4,800 
fewer non-fatal heart attacks, 2,600 fewer hospitalizations (for 
respiratory and cardiovascular disease combined), 3.2 million fewer 
days of restricted activity due to respiratory illness and 
approximately 540,000 fewer lost work days. As described in EO 13045, 
Protection of Children from Environmental Health Risks and Safety 
Risks, we also estimate substantial health improvements for children.
    We also examined the PM2.5 mortality risks according to 
race, income, and educational attainment. We then estimated the change 
in PM2.5 mortality risk as a result of this final rule among 
people living in the counties with the highest (top 5 percent) 
PM2.5 mortality risk in 2005. We then compared the change in 
risk among the people living in these ``high-risk'' counties with 
people living in all other counties.
    In 2005, people living in the highest risk counties and in the 
poorest counties had a substantially higher risk of PM2.5-
related death than people living in the other 95 percent of counties. 
This was

[[Page 9446]]

true regardless of race; the difference between the groups of counties 
for each race was large while the differences among races in both 
groups of counties was very small. In contrast, the analysis found that 
people with less than high school education had a significantly greater 
risk from PM2.5 mortality than people with a greater than 
high school education. This was true both for the highest-risk counties 
and for the other counties. In summary, the analysis indicates that in 
2005, educational status, living in one of the poorest counties, and 
living in a high-risk county are associated with higher 
PM2.5 mortality risk while race is not.
    Our analysis demonstrates that this final rule will significantly 
reduce the PM2.5 mortality among all populations of 
different races living throughout the U.S. compared to both 2005 and 
2016 pre-rule (i.e., base case) levels. The analysis indicates that 
people living in counties with the highest rates (top 5 percent) of 
PM2.5 mortality risk in 2005 receive the largest reduction 
in mortality risk after this rule takes effect. We also find that 
people living in the poorest 5 percent of the counties receive a larger 
reduction in PM2.5 mortality risk than all other counties. 
More information can be found in Section 7.11 of the RIA.
    The EPA estimates that the benefits of the final rule are 
distributed among races, income levels, and levels of education fairly 
evenly. However, the analysis does indicate that this final rule in 
conjunction with the implementation of existing or final rules (e.g., 
the CSAPR) will reduce the disparity in risk between those in the 
highest-risk counties and the other 95 percent of counties for all 
races and educational levels. In addition, in many cases implementation 
of this final rule and other rules will, together, reduce risks in the 
highest-risk counties to the approximate level of risk for the rest of 
the counties as it existed before implementation of the rule.
    These results are presented in more detail in Section 7.11 of the 
RIA.
3. Meaningful Public Participation
    The EPA defines ``environmental justice'' to include meaningful 
involvement of all people regardless of race, color, national origin, 
or income with respect to the development, implementation, and 
enforcement of environmental laws, regulations, and policies. To 
promote meaningful involvement, the EPA publicized the rulemaking via 
newsletters, EJ listserves, and the internet, including the Office of 
Policy's (OP) Rulemaking Gateway Web site (http://yosemite.epa.gov/opei/RuleGate.nsf/). During the comment period, the EPA discussed the 
proposed rule via a conference call with communities, conducted a 
community-oriented webinar on the proposed rule, and posted the webinar 
presentation on- line. The EPA also held three public hearings to 
receive additional input on the proposal.
    There will continue to be opportunities for public notice and 
comment as the utilities move forward with implementation of this rule. 
Once the rule is finalized, affected EGUs will need to update their 
Title V operating permits to reflect their new emission limits, any 
other new applicable requirements, and the associated monitoring and 
recordkeeping from this rule. The Title V permitting process provides 
that when most permits are reopened (for example, to incorporate new 
applicable requirements) or renewed, there must be opportunity for 
public review and comments. In addition, after the public review 
process, the EPA has an opportunity to review the proposed permit and 
object to its issuance if it does not meet CAA requirements.
4. Additional Analysis
    In addition to the previously described assessment of EJ impacts, 
the EPA conducted an analysis of sub-populations with particularly high 
potential risks of Hg exposure due to high rates of fish consumption. 
These populations overlap in many cases with traditional EJ populations 
and would benefit from Hg reductions resulting from this rule. The EPA 
also conducted an analysis of the distribution of PM2.5-
related mortality risk according to the race, income and education of 
the population and how MATS changes this distribution. These analyses 
can be found in Section 7.12 of the RIA.
5. Summary
    This final rule strictly limits the emissions rate of Hg and other 
HAP from every affected EGU. The EPA's analysis indicates substantial 
health benefits, including for minority, low income, and indigenous 
populations, from reductions in PM2.5.
    The EPA's analysis also indicates reductions in risks for 
individuals, including for members of minority populations, who eat 
fish frequently from U.S. lakes and rivers and who live near affected 
sources. Based on all the available information, the EPA has determined 
that this final rule will not have disproportionately high and adverse 
human health or environmental effects on minority, low income, and 
indigenous populations. The EPA is providing multiple opportunities for 
EJ communities to both learn about and comment on this rule and 
welcomes their participation as implementation of the rule proceeds.

K. Congressional Review Act

    The Congressional Review Act, 5 U.S.C. 801 et seq., as added by the 
Small Business Regulatory Enforcement Fairness Act of 1996, generally 
provides that before a rule may take effect, the agency promulgating 
the rule must submit a rule report, which includes a copy of the rule, 
to each House of the Congress and to the Comptroller General of the 
U.S. The EPA will submit a report containing this rule and other 
required information to the U.S. Senate, the U.S. House of 
Representatives, and the Comptroller General of the U.S. prior to 
publication of the rule in the Federal Register. A major rule cannot 
take effect until 60 days after it is published in the Federal 
Register. This action is a ``major rule'' as defined by 5 U.S.C. 
804(2). This rule will be effective April 16, 2012.

List of Subjects

40 CFR Part 60

    Environmental protection, Administrative practice and procedure, 
Air pollution control, Incorporation by reference, Intergovernmental 
relations, Reporting and recordkeeping requirements.

40 CFR Part 63

    Environmental protection, Administrative practice and procedure, 
Air pollution control, Hazardous substances, Incorporation by 
reference, Intergovernmental relations, Reporting and recordkeeping 
requirements.

    Dated: December 16, 2011.
Lisa P. Jackson,
Administrator.

    For the reasons stated in the preamble, title 40, chapter I, of the 
Code of the Federal Regulations is amended as follows:

PART 60--[AMENDED]

0
1. The authority citation for part 60 continues to read as follows:

    Authority:  42 U.S.C. 7401 et seq.

Subpart A--[Amended]

0
2. Section 60.17 is amended:
0
a. By redesignating paragraph (a)(93), added March 21, 2011, at 76 FR 
15750, and delayed indefinitely at 76 FR 28664, May 18, 2011, as 
paragraph (a)(96);

[[Page 9447]]

0
b. By redesignating paragraphs (a)(91) and (a)(92) as paragraphs 
(a)(94) and (a)(95);
0
c. By redesignating paragraphs (a)(89) and (a)(90) as paragraphs 
(a)(91) and (a)(92);
0
d. By redesignating paragraphs (a)(54) through (a)(88) as paragraphs 
(a)(55) through (a)(89);
0
e. By adding paragraph (a)(54);
0
f. By adding paragraph (a)(90); and
0
g. By adding paragraph (a)(93) to read as follows:


Sec.  60.17  Incorporations by reference.

* * * * *
    (a) * * *
    (54) ASTM D3699-08, Standard Specification for Kerosine, including 
Appendix X1, approved September 1, 2008, IBR approved for Sec. Sec.  
60.41b of subpart Db of this part and 60.41c of subpart Dc of this 
part.
* * * * *
    (90) ASTM D6751-11b, Standard Specification for Biodiesel Fuel 
Blend Stock (B100) for Middle Distillate Fuels, including Appendices X1 
through X3, approved July 15, 2011, IBR approved for Sec. Sec.  60.41b 
of subpart Db of this part and 60.41c of subpart Dc of this part.
* * * * *
    (93) ASTM D7467-10, Standard Specification for Diesel Fuel Oil, 
Biodiesel Blend (B6 to B20), including Appendices X1 through X3, 
approved August 1, 2010, IBR approved for Sec. Sec.  60.41b of subpart 
Db of this part and 60.41c of subpart Dc of this part.
* * * * *

Subpart B--[Amended]

0
3. Section 60.21 is amended as follows:
0
a. By revising paragraph (a).
0
b. By revising paragraph (f).
0
c. By removing paragraph (k).


Sec.  60.21  Definitions.

* * * * *
    (a) Designated pollutant means any air pollutant, the emissions of 
which are subject to a standard of performance for new stationary 
sources, but for which air quality criteria have not been issued and 
that is not included on a list published under section 108(a) or 
section 112(b)(1)(A) of the Act.
* * * * *
    (f) Emission standard means a legally enforceable regulation 
setting forth an allowable rate of emissions into the atmosphere, 
establishing an allowance system, or prescribing equipment 
specifications for control of air pollution emissions.
* * * * *

0
4. Section 60.24 is amended as follows:
0
a. By revising paragraph (b)(1).
0
b. By removing paragraph (h).


Sec.  60.24  Emission standards and compliance schedules.

* * * * *
    (b) * * *
    (1) Emission standards shall either be based on an allowance system 
or prescribe allowable rates of emissions except when it is clearly 
impracticable. Such cases will be identified in the guideline documents 
issued under Sec.  60.22. Where emission standards prescribing 
equipment specifications are established, the plan shall, to the degree 
possible, set forth the emission reductions achievable by 
implementation of such specifications, and may permit compliance by the 
use of equipment determined by the State to be equivalent to that 
prescribed.
* * * * *

Subpart D--[Amended]

0
5. The subpart heading for Subpart D is revised to read as follows:

Subpart D--Standards of Performance for Fossil-Fuel-Fired Steam 
Generators

0
6. Section 60.40 is amended by revising paragraph (e) to read as 
follows:


Sec.  60.40  Applicability and designation of affected facility.

* * * * *
    (e) Any facility subject to either subpart Da or KKKK of this part 
is not subject to this subpart.

0
7. Section 60.41 is amended by adding the definition of ``natural gas'' 
in alphabetical order to read as follows:


Sec.  60.41  Definitions.

* * * * *
    Natural gas means a fluid mixture of hydrocarbons (e.g., methane, 
ethane, or propane), composed of at least 70 percent methane by volume 
or that has a gross calorific value between 35 and 41 megajoules (MJ) 
per dry standard cubic meter (950 and 1,100 Btu per dry standard cubic 
foot), that maintains a gaseous state under ISO conditions. In 
addition, natural gas contains 20.0 grains or less of total sulfur per 
100 standard cubic feet. Finally, natural gas does not include the 
following gaseous fuels: landfill gas, digester gas, refinery gas, sour 
gas, blast furnace gas, coal-derived gas, producer gas, coke oven gas, 
or any gaseous fuel produced in a process which might result in highly 
variable sulfur content or heating value.
* * * * *

0
8. Section 60.42 is amended as follows:
0
a. By revising paragraph (a) introductory text.
0
b. By adding paragraph (d).
0
c. By adding paragraph (e).


Sec.  60.42  Standard for particulate matter (PM).

    (a) Except as provided under paragraphs (b), (c), (d), and (e) of 
this section, on and after the date on which the performance test 
required to be conducted by Sec.  60.8 is completed, no owner or 
operator subject to the provisions of this subpart shall cause to be 
discharged into the atmosphere from any affected facility any gases 
that:
* * * * *
    (d) An owner or operator of an affected facility that combusts only 
natural gas is exempt from the PM and opacity standards specified in 
paragraph (a) of this section.
    (e) An owner or operator of an affected facility that combusts only 
gaseous or liquid fossil fuel (excluding residual oil) with potential 
SO2 emissions rates of 26 ng/J (0.060 lb/MMBtu) or less and 
that does not use post-combustion technology to reduce emissions of 
SO2 or PM is exempt from the PM standards specified in 
paragraph (a) of this section.

0
9. Section 60.45 is amended as follows:
0
a. By revising paragraph (a).
0
b. By revising paragraph (b) introductory text.
0
c. By revising paragraphs (b)(1) through (5).
0
d. By revising paragraph (b)(6) introductory text.
0
e. By revising paragraphs (b)(7)(i)(A) through (C).
0
f. By revising paragraph (b)(7)(ii)(B).
0
g. By adding paragraph (b)(8).


Sec.  60.45  Emissions and fuel monitoring.

    (a) Each owner or operator of an affected facility subject to the 
applicable emissions standard shall install, calibrate, maintain, and 
operate continuous opacity monitoring system (COMS) for measuring 
opacity and a continuous emissions monitoring system (CEMS) for 
measuring SO2 emissions, NOX emissions, and 
either oxygen (O2) or carbon dioxide (CO2) except 
as provided in paragraph (b) of this section.
    (b) Certain of the CEMS and COMS requirements under paragraph (a) 
of this section do not apply to owners or operators under the following 
conditions:
    (1) For a fossil-fuel-fired steam generator that combusts only 
gaseous or liquid fossil fuel (excluding residual oil)

[[Page 9448]]

with potential SO2 emissions rates of 26 ng/J (0.060 lb/
MMBtu) or less and that does not use post-combustion technology to 
reduce emissions of SO2 or PM, COMS for measuring the 
opacity of emissions and CEMS for measuring SO2 emissions 
are not required if the owner or operator monitors SO2 
emissions by fuel sampling and analysis or fuel receipts.
    (2) For a fossil-fuel-fired steam generator that does not use a 
flue gas desulfurization device, a CEMS for measuring SO2 
emissions is not required if the owner or operator monitors 
SO2 emissions by fuel sampling and analysis.
    (3) Notwithstanding Sec.  60.13(b), installation of a CEMS for 
NOX may be delayed until after the initial performance tests 
under Sec.  60.8 have been conducted. If the owner or operator 
demonstrates during the performance test that emissions of 
NOX are less than 70 percent of the applicable standards in 
Sec.  60.44, a CEMS for measuring NOX emissions is not 
required. If the initial performance test results show that 
NOX emissions are greater than 70 percent of the applicable 
standard, the owner or operator shall install a CEMS for NOX 
within one year after the date of the initial performance tests under 
Sec.  60.8 and comply with all other applicable monitoring requirements 
under this part.
    (4) If an owner or operator is not required to and elects not to 
install any CEMS for either SO2 or NOX, a CEMS 
for measuring either O2 or CO2 is not required.
    (5) For affected facilities using a PM CEMS, a bag leak detection 
system to monitor the performance of a fabric filter (baghouse) 
according to the most current requirements in Sec.  60.48Da of this 
part, or an ESP predictive model to monitor the performance of the ESP 
developed in accordance and operated according to the most current 
requirements in section Sec.  60.48Da of this part a COMS is not 
required.
    (6) A COMS for measuring the opacity of emissions is not required 
for an affected facility that does not use post-combustion technology 
(except a wet scrubber) for reducing PM, SO2, or carbon 
monoxide (CO) emissions, burns only gaseous fuels or fuel oils that 
contain less than or equal to 0.30 weight percent sulfur, and is 
operated such that emissions of CO to the atmosphere from the affected 
source are maintained at levels less than or equal to 0.15 lb/MMBtu on 
a boiler operating day average basis. Owners and operators of affected 
sources electing to comply with this paragraph must demonstrate 
compliance according to the procedures specified in paragraphs 
(b)(6)(i) through (iv) of this section.
* * * * *
    (7) * * *
    (i) * * *
    (A) If no visible emissions are observed, a subsequent Method 9 of 
appendix A-4 of this part performance test must be completed within 12 
calendar months from the date that the most recent performance test was 
conducted or within 45 days of the next day that fuel with an opacity 
standard is combusted, whichever is later;
    (B) If visible emissions are observed but the maximum 6-minute 
average opacity is less than or equal to 5 percent, a subsequent Method 
9 of appendix A-4 of this part performance test must be completed 
within 6 calendar months from the date that the most recent performance 
test was conducted or within 45 days of the next day that fuel with an 
opacity standard is combusted, whichever is later;
    (C) If the maximum 6-minute average opacity is greater than 5 
percent but less than or equal to 10 percent, a subsequent Method 9 of 
appendix A-4 of this part performance test must be completed within 3 
calendar months from the date that the most recent performance test was 
conducted or within 45 days of the next day that fuel with an opacity 
standard is combusted, whichever is later; or
* * * * *
    (ii) * * *
    (B) If no visible emissions are observed for 10 operating days 
during which an opacity standard is applicable, observations can be 
reduced to once every 7 operating days during which an opacity standard 
is applicable. If any visible emissions are observed, daily 
observations shall be resumed.
* * * * *
    (8) A COMS for measuring the opacity of emissions is not required 
for an affected facility at which the owner or operator installs, 
calibrates, operates, and maintains a particulate matter continuous 
parametric monitoring system (PM CPMS) according to the requirements 
specified in subpart UUUUU of part 63.
* * * * *

Subpart Da--[Amended]

0
10. The subpart heading for Subpart Da is revised to read as follows:

Subpart Da--Standards of Performance for Electric Utility Steam 
Generating Units

0
11. Section 60.40Da is amended by revising paragraphs (b)(1) and (e) to 
read as follows:


Sec.  60.40Da  Applicability and designation of affected facility.

* * * * *
    (b) * * *
    (1) The IGCC electric utility steam generating unit is capable of 
combusting more than 73 MW (250 MMBtu/h) heat input of fossil fuel 
(either alone or in combination with any other fuel) in the combustion 
turbine engine and associated heat recovery steam generator; and
* * * * *
    (e) Applicability of this subpart to an electric utility combined 
cycle gas turbine other than an IGCC electric utility steam generating 
unit is as specified in paragraphs (e)(1) through (3) of this section.
    (1) Affected facilities (i.e. heat recovery steam generators used 
with duct burners) associated with a stationary combustion turbine that 
are capable of combusting more than 73 MW (250 MMBtu/h) heat input of 
fossil fuel are subject to this subpart except in cases when the 
affected facility (i.e. heat recovery steam generator) meets the 
applicability requirements of and is subject to subpart KKKK of this 
part.
    (2) For heat recovery steam generators use with duct burners 
subject to this subpart, only emissions resulting from the combustion 
of fuels in the steam generating unit (i.e. duct burners) are subject 
to the standards under this subpart. (The emissions resulting from the 
combustion of fuels in the stationary combustion turbine engine are 
subject to subpart GG or KKKK, as applicable, of this part.)
    (3) Any affected facility that meets the applicability requirements 
and is subject to subpart Eb or subpart CCCC of this part is not 
subject to the emission standards under subpart Da.

0
12. Section 60.41Da is amended as follows:
0
a. By revising the definitions of ``boiler operating day'', ``gaseous 
fuel'', ``integrated gasification combined cycle electric utility steam 
generating unit'', ``natural gas'', ``petroleum'', ``potential 
combustion concentration'', and ``steam generating unit''.
0
b. By adding the definitions of ``affirmative defense'', ``combined 
heat and power'', ``gross energy output'', ``net energy output'', 
``out-of-control period'', and ``petroleum coke'' in alphabetical 
order.

[[Page 9449]]

0
c. By removing the definitions of ``available purchase power'', 
``cogeneration'', ``dry flue gas desulfurization technology ``, 
``electric utility company'', ``emergency condition'', ``emission rate 
period'', ``gross output'', ``interconnected'', ``net system 
capacity'', ``principal company'', ``responsible official'', ``spare 
flue gas desulfurization system module'', ``spinning reserve'', 
``system emergency reserves'', and ``system load''.


Sec.  60.41Da  Definitions.

* * * * *
    Affirmative defense means, in the context of an enforcement 
proceeding, a response or defense put forward by a defendant, regarding 
which the defendant has the burden of proof, and the merits of which 
are independently and objectively evaluated in a judicial or 
administrative proceeding.
* * * * *
    Boiler operating day for units constructed, reconstructed, or 
modified before February 29, 2005, means a 24-hour period during which 
fossil fuel is combusted in a steam-generating unit for the entire 24 
hours. For units constructed, reconstructed, or modified after February 
28, 2005, boiler operating day means a 24-hour period between 12 
midnight and the following midnight during which any fuel is combusted 
at any time in the steam-generating unit. It is not necessary for fuel 
to be combusted the entire 24-hour period.
* * * * *
    Combined heat and power, also known as ``cogeneration,'' means a 
steam-generating unit that simultaneously produces both electric (and 
mechanical) and useful thermal energy from the same primary energy 
source.
* * * * *
    Gaseous fuel means any fuel that is present as a gas at standard 
conditions and includes, but is not limited to, natural gas, refinery 
fuel gas, process gas, coke-oven gas, synthetic gas, and gasified coal.
* * * * *
    Gross energy output means:
    (1) For facilities constructed, reconstructed, or modified before 
May 4, 2011, the gross electrical or mechanical output from the 
affected facility plus 75 percent of the useful thermal output measured 
relative to ISO conditions that is not used to generate additional 
electrical or mechanical output or to enhance the performance of the 
unit (i.e., steam delivered to an industrial process);
    (2) For facilities constructed, reconstructed, or modified after 
May 3, 2011, the gross electrical or mechanical output from the 
affected facility minus any electricity used to power the feedwater 
pumps and any associated gas compressors (air separation unit main 
compressor, oxygen compressor, and nitrogen compressor) plus 75 percent 
of the useful thermal output measured relative to ISO conditions that 
is not used to generate additional electrical or mechanical output or 
to enhance the performance of the unit (i.e., steam delivered to an 
industrial process);
    (3) For combined heat and power facilities constructed, 
reconstructed, or modified after May 3, 2011, the gross electrical or 
mechanical output from the affected facility divided by 0.95 minus any 
electricity used to power the feedwater pumps and any associated gas 
compressors (air separation unit main compressor, oxygen compressor, 
and nitrogen compressor) plus 75 percent of the useful thermal output 
measured relative to ISO conditions that is not used to generate 
additional electrical or mechanical output or to enhance the 
performance of the unit (i.e., steam delivered to an industrial 
process);
    (4) For a IGCC electric utility generating unit that coproduces 
chemicals constructed, reconstructed, or modified after May 3, 2011, 
the gross useful work performed is the gross electrical or mechanical 
output from the unit minus electricity used to power the feedwater 
pumps and any associated gas compressors (air separation unit main 
compressor, oxygen compressor, and nitrogen compressor) that are 
associated with power production plus 75 percent of the useful thermal 
output measured relative to ISO conditions that is not used to generate 
additional electrical or mechanical output or to enhance the 
performance of the unit (i.e., steam delivered to an industrial 
process). Auxiliary loads that are associated with power production are 
determined based on the energy in the coproduced chemicals compared to 
the energy of the syngas combusted in combustion turbine engine and 
associated duct burners.
* * * * *
    Integrated gasification combined cycle electric utility steam 
generating unit or IGCC electric utility steam generating unit means an 
electric utility combined cycle gas turbine that is designed to burn 
fuels containing 50 percent (by heat input) or more solid-derived fuel 
not meeting the definition of natural gas. The Administrator may waive 
the 50 percent solid-derived fuel requirement during periods of the 
gasification system construction or repair. No solid fuel is directly 
burned in the unit during operation.
* * * * *
    Natural gas means a fluid mixture of hydrocarbons (e.g., methane, 
ethane, or propane), composed of at least 70 percent methane by volume 
or that has a gross calorific value between 35 and 41 megajoules (MJ) 
per dry standard cubic meter (950 and 1,100 Btu per dry standard cubic 
foot), that maintains a gaseous state under ISO conditions. In 
addition, natural gas contains 20.0 grains or less of total sulfur per 
100 standard cubic feet. Finally, natural gas does not include the 
following gaseous fuels: landfill gas, digester gas, refinery gas, sour 
gas, blast furnace gas, coal-derived gas, producer gas, coke oven gas, 
or any gaseous fuel produced in a process which might result in highly 
variable sulfur content or heating value.
    Net energy output means the gross energy output minus the parasitic 
load associated with power production. Parasitic load includes, but is 
not limited to, the power required to operate the equipment used for 
fuel delivery systems, air pollution control systems, wastewater 
treatment systems, ash handling and disposal systems, and other 
controls (i.e., pumps, fans, compressors, motors, instrumentation, and 
other ancillary equipment required to operate the affected facility).
* * * * *
    Out-of-control period means any period beginning with the quadrant 
corresponding to the completion of a daily calibration error, linearity 
check, or quality assurance audit that indicates that the instrument is 
not measuring and recording within the applicable performance 
specifications and ending with the quadrant corresponding to the 
completion of an additional calibration error, linearity check, or 
quality assurance audit following corrective action that demonstrates 
that the instrument is measuring and recording within the applicable 
performance specifications.
    Petroleum for facilities constructed, reconstructed, or modified 
before May 4, 2011, means crude oil or a fuel derived from crude oil, 
including, but not limited to, distillate oil, and residual oil. For 
units constructed, reconstructed, or modified after May 3, 2011, 
petroleum means crude oil or a fuel derived from crude oil, including, 
but not limited to, distillate oil, residual oil, and petroleum coke.
    Petroleum coke, also known as ``petcoke,'' means a carbonization 
product of high-boiling hydrocarbon fractions obtained in petroleum 
processing (heavy residues). Petroleum

[[Page 9450]]

coke is typically derived from oil refinery coker units or other 
cracking processes.
    Potential combustion concentration means the theoretical emissions 
(nanograms per joule (ng/J), lb/MMBtu heat input) that would result 
from combustion of a fuel in an uncleaned state without emission 
control systems. For sulfur dioxide (SO2) the potential 
combustion concentration is determined under Sec.  60.50Da(c).
* * * * *
    Steam generating unit for facilities constructed, reconstructed, or 
modified before May 4, 2011, means any furnace, boiler, or other device 
used for combusting fuel for the purpose of producing steam (including 
fossil-fuel-fired steam generators associated with combined cycle gas 
turbines; nuclear steam generators are not included). For units 
constructed, reconstructed, or modified after May 3, 2011, steam 
generating unit means any furnace, boiler, or other device used for 
combusting fuel for the purpose of producing steam (including fossil-
fuel-fired steam generators associated with combined cycle gas 
turbines; nuclear steam generators are not included) plus any 
integrated combustion turbines and fuel cells.
* * * * *
0
13. Section 60.42Da is revised to read as follows:


Sec.  60.42Da  Standards for particulate matter (PM).

    (a) Except as provided in paragraph (f) of this section, on and 
after the date on which the initial performance test is completed or 
required to be completed under Sec.  60.8, whichever date comes first, 
an owner or operator of an affected facility shall not cause to be 
discharged into the atmosphere from any affected facility for which 
construction, reconstruction, or modification commenced before March 1, 
2005, any gases that contain PM in excess of 13 ng/J (0.030 lb/MMBtu) 
heat input.
    (b) Except as provided in paragraphs (b)(1) and (b)(2) of this 
section, on and after the date the initial PM performance test is 
completed or required to be completed under Sec.  60.8, whichever date 
comes first, an owner or operator of an affected facility shall not 
cause to be discharged into the atmosphere any gases which exhibit 
greater than 20 percent opacity (6-minute average), except for one 6-
minute period per hour of not more than 27 percent opacity.
    (1) An owner or operator of an affected facility that elects to 
install, calibrate, maintain, and operate a continuous emissions 
monitoring system (CEMS) for measuring PM emissions according to the 
requirements of this subpart is exempt from the opacity standard 
specified in this paragraph (b) of this section.
    (2) An owner or operator of an affected facility that combusts only 
natural gas is exempt from the opacity standard specified in paragraph 
(b) of this section.
    (c) Except as provided in paragraphs (d) and (f) of this section, 
on and after the date on which the initial performance test is 
completed or required to be completed under Sec.  60.8, whichever date 
comes first, no owner or operator of an affected facility that 
commenced construction, reconstruction, or modification after February 
28, 2005, but before May 4, 2011, shall cause to be discharged into the 
atmosphere from that affected facility any gases that contain PM in 
excess of either:
    (1) 18 ng/J (0.14 lb/MWh) gross energy output; or
    (2) 6.4 ng/J (0.015 lb/MMBtu) heat input derived from the 
combustion of solid, liquid, or gaseous fuel.
    (d) As an alternative to meeting the requirements of paragraph (c) 
of this section, the owner or operator of an affected facility for 
which construction, reconstruction, or modification commenced after 
February 28, 2005, but before May 4, 2011, may elect to meet the 
requirements of this paragraph. On and after the date on which the 
initial performance test is completed or required to be completed under 
Sec.  60.8, whichever date comes first, no owner or operator of an 
affected facility shall cause to be discharged into the atmosphere from 
that affected facility any gases that contain PM in excess of:
    (1) 13 ng/J (0.030 lb/MMBtu) heat input derived from the combustion 
of solid, liquid, or gaseous fuel, and
    (2) For an affected facility that commenced construction or 
reconstruction, 0.1 percent of the combustion concentration determined 
according to the procedure in Sec.  60.48Da(o)(5) (99.9 percent 
reduction) when combusting solid, liquid, or gaseous fuel, or
    (3) For an affected facility that commenced modification, 0.2 
percent of the combustion concentration determined according to the 
procedure in Sec.  60.48Da(o)(5) (99.8 percent reduction) when 
combusting solid, liquid, or gaseous fuel.
    (e) Except as provided in paragraph (f) of this section, the owner 
or operator of an affected facility that commenced construction, 
reconstruction, or modification commenced after May 3, 2011, shall meet 
the requirements specified in paragraphs (e)(1) and (2) of this 
section.
    (1) On and after the date on which the initial performance test is 
completed or required to be completed under Sec.  60.8, whichever date 
comes first, no owner or operator shall cause to be discharged into the 
atmosphere from that affected facility at all times except during 
periods of startup and shutdown, any gases that contain PM in excess of 
the applicable emissions limit specified in paragraphs (e)(1)(i) or 
(ii) of this section.
    (i) For an affected facility which commenced construction or 
reconstruction, any gases that contain PM in excess of either:
    (A) 11 ng/J (0.090 lb/MWh) gross energy output; or
    (B) 12 ng/J (0.097 lb/MWh) net energy output.
    (ii) For an affected facility which commenced modification, any 
gases that contain PM in excess of 13 ng/J (0.015 lb/MMBtu) heat input.
    (2) During periods of startup and shutdown, the owner or operator 
shall meet the work practice standards specified in Table 3 to subpart 
UUUUU of part 63.
    (f) An owner or operator of an affected facility that meets the 
conditions in either paragraphs (f)(1) or (2) of this section is exempt 
from the PM emissions limits in this section.
    (1) The affected facility combusts only gaseous or liquid fuels 
(excluding residual oil) with potential SO2 emissions rates 
of 26 ng/J (0.060 lb/MMBtu) or less, and that does not use a post-
combustion technology to reduce emissions of SO2 or PM.
    (2) The affected facility is operated under a PM commercial 
demonstration permit issued by the Administrator according to the 
provisions of Sec.  60.47Da.

0
14. Section 60.43Da is amended as follows:
0
a. The section heading is revised.
0
b. By revising paragraphs (a)(1) and (2).
0
c. By adding paragraphs (a)(3) and (4).
0
d. By removing and reserving paragraph (c).
0
e. By revising paragraph (f).
0
f. By revising paragraph (i).
0
g. By revising paragraph (k).
0
h. By adding paragraph (l).
0
i. By adding paragraph (m).


Sec.  60.43Da  Standards for sulfur dioxide (SO2).

    (a) * * *
    (1) 520 ng/J (1.20 lb/MMBtu) heat input and 10 percent of the 
potential combustion concentration (90 percent reduction);
    (2) 30 percent of the potential combustion concentration (70 
percent

[[Page 9451]]

reduction), when emissions are less than 260 ng/J (0.60 lb/MMBtu) heat 
input;
    (3) 180 ng/J (1.4 lb/MWh) gross energy output; or
    (4) 65 ng/J (0.15 lb/MMBtu) heat input.
* * * * *
    (f) The SO2 standards under this section do not apply to 
an owner or operator of an affected facility that is operated under an 
SO2 commercial demonstration permit issued by the 
Administrator in accordance with the provisions of Sec.  60.47Da.
* * * * *
    (i) Except as provided in paragraphs (j) and (k) of this section, 
on and after the date on which the initial performance test is 
completed or required to be completed under Sec.  60.8, whichever date 
comes first, no owner or operator of an affected facility for which 
construction, reconstruction, or modification commenced after February 
28, 2005, but before May 4, 2011, shall cause to be discharged into the 
atmosphere from that affected facility, any gases that contain 
SO2 in excess of the applicable emissions limit specified in 
paragraphs (i)(1) through (3) of this section.
    (1) For an affected facility which commenced construction, any 
gases that contain SO2 in excess of either:
    (i) 180 ng/J (1.4 lb/MWh) gross energy output; or
    (ii) 5 percent of the potential combustion concentration (95 
percent reduction).
    (2) For an affected facility which commenced reconstruction, any 
gases that contain SO2 in excess of either:
    (i) 180 ng/J (1.4 lb/MWh) gross energy output;
    (ii) 65 ng/J (0.15 lb/MMBtu) heat input; or
    (iii) 5 percent of the potential combustion concentration (95 
percent reduction).
    (3) For an affected facility which commenced modification, any 
gases that contain SO2 in excess of either:
    (i) 180 ng/J (1.4 lb/MWh) gross energy output;
    (ii) 65 ng/J (0.15 lb/MMBtu) heat input; or
    (iii) 10 percent of the potential combustion concentration (90 
percent reduction).
* * * * *
    (k) On and after the date on which the initial performance test is 
completed or required to be completed under Sec.  60.8, whichever date 
comes first, no owner or operator of an affected facility located in a 
noncontinental area for which construction, reconstruction, or 
modification commenced after February 28, 2005, but before May 4, 2011, 
shall cause to be discharged into the atmosphere from that affected 
facility any gases that contain SO2 in excess of the 
applicable emissions limit specified in paragraphs (k)(1) and (2) of 
this section.
    (1) For an affected facility that burns solid or solid-derived 
fuel, the owner or operator shall not cause to be discharged into the 
atmosphere any gases that contain SO2 in excess of 520 ng/J 
(1.2 lb/MMBtu) heat input.
    (2) For an affected facility that burns other than solid or solid-
derived fuel, the owner or operator shall not cause to be discharged 
into the atmosphere any gases that contain SO2 in excess of 
230 ng/J (0.54 lb/MMBtu) heat input.
    (l) Except as provided in paragraphs (j) and (m) of this section, 
on and after the date on which the initial performance test is 
completed or required to be completed under Sec.  60.8, whichever date 
comes first, no owner or operator of an affected facility for which 
construction, reconstruction, or modification commenced after May 3, 
2011, shall cause to be discharged into the atmosphere from that 
affected facility, any gases that contain SO2 in excess of 
the applicable emissions limit specified in paragraphs (l)(1) and (2) 
of this section.
    (1) For an affected facility which commenced construction or 
reconstruction, any gases that contain SO2 in excess of 
either:
    (i) 130 ng/J (1.0 lb/MWh) gross energy output; or
    (ii) 140 ng/J (1.2 lb/MWh) net energy output; or
    (iii) 3 percent of the potential combustion concentration (97 
percent reduction).
    (2) For an affected facility which commenced modification, any 
gases that contain SO2 in excess of either:
    (i) 180 ng/J (1.4 lb/MWh) gross energy output; or
    (ii) 10 percent of the potential combustion concentration (90 
percent reduction).
    (m) On and after the date on which the initial performance test is 
completed or required to be completed under Sec.  60.8, whichever date 
comes first, no owner or operator of an affected facility located in a 
noncontinental area for which construction, reconstruction, or 
modification commenced after May 3, 2011, shall cause to be discharged 
into the atmosphere from that affected facility any gases that contain 
SO2 in excess of the applicable emissions limit specified in 
paragraphs (m)(1) and (2) of this section.
    (1) For an affected facility that burns solid or solid-derived 
fuel, the owner or operator shall not cause to be discharged into the 
atmosphere any gases that contain SO2 in excess of 520 ng/J 
(1.2 lb/MMBtu) heat input.
    (2) For an affected facility that burns other than solid or solid-
derived fuel, the owner or operator shall not cause to be discharged 
into the atmosphere any gases that contain SO2 in excess of 
230 ng/J (0.54 lb/MMBtu) heat input.
0
15. Section 60.44Da is revised to read as follows:


Sec.  60.44Da  Standards for nitrogen oxides (NOX).

    (a) Except as provided in paragraph (h) of this section, on and 
after the date on which the initial performance test is completed or 
required to be completed under Sec.  60.8, whichever date comes first, 
no owner or operator subject to the provisions of this subpart shall 
cause to be discharged into the atmosphere from any affected facility 
for which construction, reconstruction, or modification commenced 
before July 10, 1997 any gases that contain NOX (expressed 
as NO2) in excess of the applicable emissions limit in 
paragraphs (a)(1) and (2) of this section.
    (1) The owner or operator shall not cause to be discharged into the 
atmosphere any gases that contain NOX in excess of the 
emissions limit listed in the following table as applicable to the fuel 
type combusted and as determined on a 30-boiler operating day rolling 
average basis.

------------------------------------------------------------------------
                                                 Emission limit for heat
                                                          input
                   Fuel type                   -------------------------
                                                    ng/J       lb/MMBtu
------------------------------------------------------------------------
Gaseous fuels:
    Coal-derived fuels........................          210         0.50
    All other fuels...........................           86         0.20
Liquid fuels:

[[Page 9452]]

 
    Coal-derived fuels........................          210         0.50
    Shale oil.................................          210         0.50
    All other fuels...........................          130         0.30
Solid fuels:
    Coal-derived fuels........................          210         0.50
    Any fuel containing more than 25%, by               (1)          (1)
     weight, coal refuse......................
Any fuel containing more than 25%, by weight,           340         0.80
 lignite if the lignite is mined in North
 Dakota, South Dakota, or Montana, and is
 combusted in a slag tap furnace \2\..........
Any fuel containing more than 25%, by weight,           260         0.60
 lignite not subject to the 340 ng/J heat
 input emission limit \2\.....................
Subbituminous coal............................          210         0.50
Bituminous coal...............................          260         0.60
Anthracite coal...............................          260         0.60
All other fuels...............................          260         0.60
------------------------------------------------------------------------
\1\ Exempt from NOX standards and NOX monitoring requirements.
\2\ Any fuel containing less than 25%, by weight, lignite is not
  prorated but its percentage is added to the percentage of the
  predominant fuel.

    (2) When two or more fuels are combusted simultaneously in an 
affected facility, the applicable emissions limit (En) is 
determined by proration using the following formula:
[GRAPHIC] [TIFF OMITTED] TR16FE12.019

Where:

En = Applicable NOX emissions limit when multiple fuels 
are combusted simultaneously (ng/J heat input);
w = Percentage of total heat input derived from the combustion of 
fuels subject to the 86 ng/J heat input standard;
x = Percentage of total heat input derived from the combustion of 
fuels subject to the 130 ng/J heat input standard;
y = Percentage of total heat input derived from the combustion of 
fuels subject to the 210 ng/J heat input standard;
z = Percentage of total heat input derived from the combustion of 
fuels subject to the 260 ng/J heat input standard; and
v = Percentage of total heat input delivered from the combustion of 
fuels subject to the 340 ng/J heat input standard.

    (b) [Reserved]
    (c) [Reserved]
    (d) Except as provided in paragraph (h) of this section, on and 
after the date on which the initial performance test is completed or 
required to be completed under Sec.  60.8, whichever date comes first, 
no owner or operator of an affected facility that commenced 
construction, reconstruction, or modification after July 9, 1997, but 
before March 1, 2005, shall cause to be discharged into the atmosphere 
from that affected facility any gases that contain NOX 
(expressed as NO2) in excess of the applicable emissions 
limit specified in paragraphs (d)(1) and (2) of this section as 
determined on a 30-boiler operating day rolling average basis.
    (1) For an affected facility which commenced construction, any 
gases that contain NOX in excess of 200 ng/J (1.6 lb/MWh) 
gross energy output.
    (2) For an affected facility which commenced reconstruction, any 
gases that contain NOX in excess of 65 ng/J (0.15 lb/MMBtu) 
heat input.
    (e) Except as provided in paragraphs (f) and (h) of this section, 
on and after the date on which the initial performance test is 
completed or required to be completed under Sec.  60.8, whichever date 
comes first, no owner or operator of an affected facility that 
commenced construction, reconstruction, or modification after February 
28, 2005 but before May 4, 2011, shall cause to be discharged into the 
atmosphere from that affected facility any gases that contain 
NOX (expressed as NO2) in excess of the 
applicable emissions limit specified in paragraphs (e)(1) through (3) 
of this section as determined on a 30-boiler operating day rolling 
average basis.
    (1) For an affected facility which commenced construction, any 
gases that contain NOX in excess of 130 ng/J (1.0 lb/MWh) 
gross energy output.
    (2) For an affected facility which commenced reconstruction, any 
gases that contain NOX in excess of either:
    (i) 130 ng/J (1.0 lb/MWh) gross energy output; or
    (ii) 47 ng/J (0.11 lb/MMBtu) heat input.
    (3) For an affected facility which commenced modification, any 
gases that contain NOX in excess of either:
    (i) 180 ng/J (1.4 lb/MWh) gross energy output; or
    (ii) 65 ng/J (0.15 lb/MMBtu) heat input.
    (f) On and after the date on which the initial performance test is 
completed or required to be completed under Sec.  60.8, whichever date 
comes first, the owner or operator of an IGCC electric utility steam 
generating unit subject to the provisions of this subpart and for which 
construction, reconstruction, or modification commenced after February 
28, 2005 but before May 4, 2011, shall meet the requirements specified 
in paragraphs (f)(1) through (3) of this section.
    (1) Except as provided for in paragraphs (f)(2) and (3) of this 
section, the owner or operator shall not cause to be discharged into 
the atmosphere any gases that contain NOX (expressed as 
NO2) in excess of 130 ng/J (1.0 lb/MWh) gross energy output.
    (2) When burning liquid fuel exclusively or in combination with 
solid-derived fuel such that the liquid fuel contributes 50 percent or 
more of the total heat input to the combined cycle combustion turbine, 
the owner or operator shall not cause to be discharged into the 
atmosphere any gases that contain NOX (expressed as 
NO2) in excess of 190 ng/J (1.5 lb/MWh) gross energy output.
    (3) In cases when during a 30-boiler operating day rolling average 
compliance period liquid fuel is burned in such a manner to meet the 
conditions in paragraph (f)(2) of this section for only a portion of 
the clock hours in the

[[Page 9453]]

30-day compliance period, the owner or operator shall not cause to be 
discharged into the atmosphere any gases that contain NOX 
(expressed as NO2) in excess of the computed weighted-
average emissions limit based on the proportion of gross energy output 
(in MWh) generated during the compliance period for each of emissions 
limits in paragraphs (f)(1) and (2) of this section.
    (g) Except as provided in paragraphs (h) of this section and Sec.  
60.45Da, on and after the date on which the initial performance test is 
completed or required to be completed under Sec.  60.8, whichever date 
comes first, no owner or operator of an affected facility that 
commenced construction, reconstruction, or modification after May 3, 
2011, shall cause to be discharged into the atmosphere from that 
affected facility any gases that contain NOX (expressed as 
NO2) in excess of the applicable emissions limit specified 
in paragraphs (g)(1) through (3) of this section.
    (1) For an affected facility which commenced construction or 
reconstruction, any gases that contain NOX in excess of 
either:
    (i) 88 ng/J (0.70 lb/MWh) gross energy output; or
    (ii) 95 ng/J (0.76 lb/MWh) net energy output.
    (2) For an affected facility which commenced construction or 
reconstruction and that burns 75 percent or more coal refuse (by heat 
input) on a 12-month rolling average basis, any gases that contain 
NOX in excess of either:
    (i) 110 ng/J (0.85 lb/MWh) gross energy output; or
    (ii) 120 ng/J (0.92 lb/MWh) net energy output.
    (3) For an affected facility which commenced modification, any 
gases that contain NOX in excess of 140 ng/J (1.1 lb/MWh) 
gross energy output.
    (h) The NOX emissions limits under this section do not 
apply to an owner or operator of an affected facility which is 
operating under a commercial demonstration permit issued by the 
Administrator in accordance with the provisions of Sec.  60.47Da.
0
16. Section 60.45Da is revised to read as follows:


Sec.  60.45Da  Alternative standards for combined nitrogen oxides (NOX) 
and carbon monoxide (CO).

    (a) The owner or operator of an affected facility that commenced 
construction, reconstruction, or modification after May 3, 2011 as 
alternate to meeting the applicable NOX emissions limits 
specified in Sec.  60.44Da may elect to meet the applicable standards 
for combined NOX and CO specified in paragraph (b) of this 
section.
    (b) On and after the date on which the initial performance test is 
completed or required to be completed under Sec.  60.8 no owner or 
operator of an affected facility that commenced construction, 
reconstruction, or modification after May 3, 2011, shall cause to be 
discharged into the atmosphere from that affected facility any gases 
that contain NOX (expressed as NO2) plus CO in 
excess of the applicable emissions limit specified in paragraphs (b)(1) 
through (3) of this section as determined on a 30-boiler operating day 
rolling average basis.
    (1) For an affected facility which commenced construction or 
reconstruction, any gases that contain NOX plus CO in excess 
of either:
    (i) 140 ng/J (1.1 lb/MWh) gross energy output; or
    (ii) 150 ng/J (1.2 lb/MWh) net energy output.
    (2) For an affected facility which commenced construction or 
reconstruction and that burns 75 percent or more coal refuse (by heat 
input) on a 12-month rolling average basis, any gases that contain 
NOX plus CO in excess of either:
    (i) 160 ng/J (1.3 lb/MWh) gross energy output; or
    (ii) 170 ng/J (1.4 lb/MWh) net energy output.
    (3) For an affected facility which commenced modification, any 
gases that contain NOX plus CO in excess of 190 ng/J (1.5 
lb/MWh) gross energy output.

0
17. Section 60.47Da is amended as follows:
0
a. By revising paragraph (c).
0
b. By adding paragraph (f).
0
c. By adding paragraph (g).
0
d. By adding paragraph (h).
0
e. By adding paragraph (i).


Sec.  60.47Da  Commercial demonstration permit.

* * * * *
    (c) An owner or operator of an affected facility that uses 
fluidized bed combustion (atmospheric or pressurized) and who is issued 
a commercial demonstration permit by the Administrator is not subject 
to the SO2 emission reduction requirements under Sec.  
60.43Da(a) but must, as a minimum, reduce SO2 emissions to 
15 percent of the potential combustion concentration (85 percent 
reduction) on a 30-day rolling average basis and to less than 520 ng/J 
(1.20 lb/MMBtu) heat input on a 30-day rolling average basis.
* * * * *
    (f) An owner or operator of an affected facility that uses a 
pressurized fluidized bed or a multi-pollutant emissions controls 
system who is issued a commercial demonstration permit by the 
Administrator is not subject to the total PM emission reduction 
requirements under Sec.  60.42Da but must, as a minimum, reduce PM 
emissions to less than 6.4 ng/J (0.015 lb/MMBtu) heat input.
    (g) An owner or operator of an affected facility that uses a 
pressurized fluidized bed or a multi-pollutant emissions controls 
system who is issued a commercial demonstration permit by the 
Administrator is not subject to the SO2 standards or 
emission reduction requirements under Sec.  60.43Da but must, as a 
minimum, reduce SO2 emissions to 5 percent of the potential 
combustion concentration (95 percent reduction) or to less than 180 ng/
J (1.4 lb/MWh) gross energy output on a 30-boiler operating day rolling 
average basis.
    (h) An owner or operator of an affected facility that uses a 
pressurized fluidized bed or a multi-pollutant emissions control system 
or advanced combustion controls who is issued a commercial 
demonstration permit by the Administrator is not subject to the 
NOX standards or emission reduction requirements under Sec.  
60.44Da but must, as a minimum, reduce NOX emissions to less 
than 130 ng/J (1.0 lb/MWh) or the combined NOX plus CO 
emissions to less than 180 ng/J (1.4 lb/MWh) gross energy output on a 
30-boiler operating day rolling average basis.
    (i) Commercial demonstration permits may not exceed the following 
equivalent MW electrical generation capacity for any one technology 
category listed in the following table.

------------------------------------------------------------------------
                                                              Equivalent
                                                              electrical
                                                               capacity
             Technology                     Pollutant            (MW
                                                              electrical
                                                               output)
------------------------------------------------------------------------
Multi-pollutant Emission Control....  SO2..................        1,000

[[Page 9454]]

 
Multi-pollutant Emission Control....  NOX..................        1,000
Multi-pollutant Emission Control....  PM...................        1,000
Pressurized Fluidized Bed Combustion  SO2..................        1,000
Pressurized Fluidized Bed Combustion  NOX..................        1,000
Pressurized Fluidized Bed Combustion  PM...................        1,000
Advanced Combustion Controls........  NOX..................        1,000
------------------------------------------------------------------------


0
18. Section 60.48Da is amended as follows:
0
a. By revising paragraphs (a) through (g).
0
b. By revising paragraph (i).
0
c. By revising paragraph (k)(1)(i).
0
d. By revising paragraph (k)(2)(i).
0
e. By revising paragraph (k)(2)(iv).
0
f. By removing and reserving paragraph (l).
0
g. By revising paragraph (m).
0
h. By revising paragraph (n).
0
i. By revising paragraphs (p)(5), (7), and (8).
0
j. By adding paragraph (r).
0
k. By adding paragraph (s).


Sec.  60.48Da  Compliance provisions.

    (a) For affected facilities for which construction, modification, 
or reconstruction commenced before May 4, 2011, the applicable PM 
emissions limit and opacity standard under Sec.  60.42Da, 
SO2 emissions limit under Sec.  60.43Da, and NOX 
emissions limit under Sec.  60.44Da apply at all times except during 
periods of startup, shutdown, or malfunction. For affected facilities 
for which construction, modification, or reconstruction commenced after 
May 3, 2011, the applicable SO2 emissions limit under Sec.  
60.43Da, NOX emissions limit under Sec.  60.44Da, and 
NOX plus CO emissions limit under Sec.  60.45Da apply at all 
times. The applicable PM emissions limit and opacity standard under 
Sec.  60.42Da apply at all times except during periods of startup and 
shutdown.
    (b) After the initial performance test required under Sec.  60.8, 
compliance with the applicable SO2 emissions limit and 
percentage reduction requirements under Sec.  60.43Da, NOX 
emissions limit under Sec.  60.44Da, and NOX plus CO 
emissions limit under Sec.  60.45Da is based on the average emission 
rate for 30 successive boiler operating days. A separate performance 
test is completed at the end of each boiler operating day after the 
initial performance test, and a new 30-boiler operating day rolling 
average emission rate for both SO2, NOX or 
NOX plus CO as applicable, and a new percent reduction for 
SO2 are calculated to demonstrate compliance with the 
standards.
    (c) For the initial performance test required under Sec.  60.8, 
compliance with the applicable SO2 emissions limits and 
percentage reduction requirements under Sec.  60.43Da, the 
NOX emissions limits under Sec.  60.44Da, and the 
NOX plus CO emissions limits under Sec.  60.45Da is based on 
the average emission rates for SO2, NOX, CO, and 
percent reduction for SO2 for the first 30 successive boiler 
operating days. The initial performance test is the only test in which 
at least 30 days prior notice is required unless otherwise specified by 
the Administrator. The initial performance test is to be scheduled so 
that the first boiler operating day of the 30 successive boiler 
operating days is completed within 60 days after achieving the maximum 
production rate at which the affected facility will be operated, but 
not later than 180 days after initial startup of the facility.
    (d) For affected facilities for which construction, modification, 
or reconstruction commenced before May 4, 2011, compliance with 
applicable 30-boiler operating day rolling average SO2 and 
NOX emissions limits is determined by calculating the 
arithmetic average of all hourly emission rates for SO2 and 
NOX for the 30 successive boiler operating days, except for 
data obtained during startup, shutdown, or malfunction. For affected 
facilities for which construction, modification, or reconstruction 
commenced after May 3, 2011, compliance with applicable 30-boiler 
operating day rolling average SO2 and NOX 
emissions limits is determined by dividing the sum of the 
SO2 and NOX emissions for the 30 successive 
boiler operating days by the sum of the gross energy output or net 
energy output, as applicable, for the 30 successive boiler operating 
days.
    (e) For affected facilities for which construction, modification, 
or reconstruction commenced before May 4, 2011, compliance with 
applicable SO2 percentage reduction requirements is 
determined based on the average inlet and outlet SO2 
emission rates for the 30 successive boiler operating days. For 
affected facilities for which construction, modification, or 
reconstruction commenced after May 3, 2011, compliance with applicable 
SO2 percentage reduction requirements is determined based on 
the ``as fired'' total potential emissions and the total outlet 
SO2 emissions for the 30 successive boiler operating days.
    (f) For affected facilities for which construction, modification, 
or reconstruction commenced before May 4, 2011, compliance with 
applicable daily average PM emissions limits is determined by 
calculating the arithmetic average of all hourly emission rates for PM 
each boiler operating day, except for data obtained during startup, 
shutdown, and malfunction. Daily averages are only calculated for 
boiler operating days that have non-out-of-control data for at least 18 
hours of unit operation during which the standard applies. Instead, all 
of the non-out-of-control hourly emission rates of the operating day(s) 
not meeting the minimum 18 hours non-out-of-control data daily average 
requirement are averaged with all of the non-out-of-control hourly 
emission rates of the next boiler operating day with 18 hours or more 
of non-out-of-control PM CEMS data to determine compliance. For 
affected facilities for which construction, modification, or 
reconstruction commenced after May 3, 2011, compliance with applicable 
daily average PM emissions limits is determined by dividing the sum of 
the PM emissions for the 30 successive boiler operating days by the sum 
of the gross useful output or net energy output, as applicable, for the 
30 successive boiler operating days.
    (g) For affected facilities for which construction, modification, 
or reconstruction commenced after May 3, 2011, compliance with 
applicable 30-boiler operating day rolling average NOX plus 
CO emissions limit is determined by dividing the sum of the 
NOX plus CO emissions for the 30 successive boiler operating 
days by the sum of the gross energy output or net energy output, as

[[Page 9455]]

applicable, for the 30 successive boiler operating days.
* * * * *
    (i) Compliance provisions for sources subject to Sec.  
60.44Da(d)(1), (e)(1), (e)(2)(i), (e)(3)(i), (f), or (g). The owner or 
operator shall calculate NOX emissions as 1.194 x 
10-7 lb/scf-ppm times the average hourly NOX 
output concentration in ppm (measured according to the provisions of 
Sec.  60.49Da(c)), times the average hourly flow rate (measured in 
scfh, according to the provisions of Sec.  60.49Da(l) or Sec.  
60.49Da(m)), divided by the average hourly gross energy output 
(measured according to the provisions of Sec.  60.49Da(k)) or the 
average hourly net energy output, as applicable. Alternatively, for 
oil-fired and gas-fired units, NOX emissions may be 
calculated by multiplying the hourly NOX emission rate in 
lb/MMBtu (measured by the CEMS required under Sec.  60.49Da(c) and 
(d)), by the hourly heat input rate (measured according to the 
provisions of Sec.  60.49Da(n)), and dividing the result by the average 
gross energy output (measured according to the provisions of Sec.  
60.49Da(k)) or the average hourly net energy output, as applicable.
    (k) * * *
    (1) * * *
    (i) The emission rate (E) of NOX shall be computed using 
Equation 2 in this section:
[GRAPHIC] [TIFF OMITTED] TR16FE12.000

Where:

E = Emission rate of NOX from the duct burner, ng/J (lb/
MWh) gross energy output;
Csg = Average hourly concentration of NOX 
exiting the steam generating unit, ng/dscm (lb/dscf);
Cte = Average hourly concentration of NOX in 
the turbine exhaust upstream from duct burner, ng/dscm (lb/dscf);
Qsg = Average hourly volumetric flow rate of exhaust gas 
from steam generating unit, dscm/h (dscf/h);
Qte = Average hourly volumetric flow rate of exhaust gas 
from combustion turbine, dscm/h (dscf/h);
Osg = Average hourly gross energy output from steam 
generating unit, J/h (MW); and
h = Average hourly fraction of the total heat input to the steam 
generating unit derived from the combustion of fuel in the affected 
duct burner.
* * * * *

    (2) * * *
    (i) The emission rate (E) of NOX shall be computed using 
Equation 3 in this section:
[GRAPHIC] [TIFF OMITTED] TR16FE12.001

Where:

E = Emission rate of NOX from the duct burner, ng/J (lb/
MWh) gross energy output;
Csg = Average hourly concentration of NOX 
exiting the steam generating unit, ng/dscm (lb/dscf);
Qsg = Average hourly volumetric flow rate of exhaust gas 
from steam generating unit, dscm/h (dscf/h); and
Occ = Average hourly gross energy output from entire 
combined cycle unit, J/h (MW).

* * * * *
    (iv) The owner or operator may, in lieu of installing, operating, 
and recording data from the continuous flow monitoring system specified 
in Sec.  60.49Da(l), determine the mass rate (lb/h) of NOX 
emissions by installing, operating, and maintaining continuous fuel 
flowmeters following the appropriate measurements procedures specified 
in appendix D of part 75 of this chapter. If this compliance option is 
selected, the emission rate (E) of NOX shall be computed 
using Equation 4 in this section:
[GRAPHIC] [TIFF OMITTED] TR16FE12.002

Where:

E = Emission rate of NOX from the duct burner, ng/J (lb/
MWh) gross energy output;
ERsg = Average hourly emission rate of NOX 
exiting the steam generating unit heat input calculated using 
appropriate F factor as described in Method 19 of appendix A of this 
part, ng/J (lb/MMBtu);
Hcc = Average hourly heat input rate of entire combined 
cycle unit, J/h (MMBtu/h); and
Occ = Average hourly gross energy output from entire 
combined cycle unit, J/h (MW).

* * * * *
    (m) Compliance provisions for sources subject to Sec.  
60.43Da(i)(1)(i), (i)(2)(i), (i)(3)(i), (j)(1)(i), (j)(2)(i), 
(j)(3)(i), (l)(1)(i), (l)(1)(ii), or (l)(2). The owner or operator 
shall calculate SO2 emissions as 1.660 x 10-7 lb/
scf-ppm times the average hourly SO2 output concentration in 
ppm (measured according to the provisions of Sec.  60.49Da(b)), times 
the average hourly flow rate (measured according to the provisions of 
Sec.  60.49Da(l) or Sec.  60.49Da(m)), divided by the average hourly 
gross energy output (measured according to the provisions of Sec.  
60.49Da(k)) or the average hourly net energy output, as applicable. 
Alternatively, for oil-fired and gas-fired units, SO2 
emissions may be calculated by multiplying the hourly SO2 
emission rate (in lb/MMBtu), measured by the CEMS required under Sec.  
60.49Da, by the hourly heat input rate (measured according to the 
provisions of Sec.  60.49Da(n)), and dividing the result by the average 
gross energy output (measured according to the provisions of Sec.  
60.49Da(k)) or the average hourly net energy output, as applicable.
    (n) Compliance provisions for sources subject to Sec.  
60.42Da(c)(1) or (e)(1)(i). The owner or operator shall calculate PM 
emissions by multiplying the average hourly PM output concentration 
(measured according to the provisions of Sec.  60.49Da(t)), by the 
average hourly flow rate (measured according to the provisions of Sec.  
60.49Da(l) or Sec.  60.49Da(m)), and dividing by the average hourly 
gross energy output (measured according to the provisions

[[Page 9456]]

of Sec.  60.49Da(k)) or the average hourly net energy output, as 
applicable.
* * * * *
    (p) * * *
    (5) At a minimum, non-out-of-control CEMS hourly averages shall be 
obtained for 75 percent of all operating hours on a 30-boiler operating 
day rolling average basis. Beginning on January 1, 2012, non-out-of-
control CEMS hourly averages shall be obtained for 90 percent of all 
operating hours on a 30-boiler operating day rolling average basis.
    (i) At least two data points per hour shall be used to calculate 
each 1-hour arithmetic average.
    (ii) [Reserved]
* * * * *
    (7) All non-out-of-control CEMS data shall be used in calculating 
average emission concentrations even if the minimum CEMS data 
requirements of paragraph (j)(5) of this section are not met.
    (8) When PM emissions data are not obtained because of CEMS 
breakdowns, repairs, calibration checks, and zero and span adjustments, 
emissions data shall be obtained by using other monitoring systems as 
approved by the Administrator or EPA Reference Method 19 of appendix A 
of this part to provide, as necessary, non-out-of-control emissions 
data for a minimum of 90 percent (only 75 percent is required prior to 
January 1, 2012) of all operating hours per 30-boiler operating day 
rolling average.
* * * * *
    (r) Compliance provisions for sources subject to Sec.  60.45Da. To 
determine compliance with the NOX plus CO emissions limit, 
the owner or operator shall use the procedures specified in paragraphs 
(r)(1) through (3) of this section.
    (1) Calculate NOX emissions as 1.194 x 10-7 
lb/scf-ppm times the average hourly NOX output concentration 
in ppm (measured according to the provisions of Sec.  60.49Da(c)), 
times the average hourly flow rate (measured in scfh, according to the 
provisions of Sec.  60.49Da(l) or Sec.  60.49Da(m)), divided by the 
average hourly gross energy output (measured according to the 
provisions of Sec.  60.49Da(k)) or the average hourly net energy 
output, as applicable.
    (2) Calculate CO emissions by multiplying the average hourly CO 
output concentration (measured according to the provisions of Sec.  
60.49Da(u), by the average hourly flow rate (measured according to the 
provisions of Sec.  60.49Da(l) or Sec.  60.49Da(m)), and dividing by 
the average hourly gross energy output (measured according to the 
provisions of Sec.  60.49Da(k)) or the average hourly net energy 
output, as applicable.
    (3) Calculate NOX plus CO emissions by summing the 
NOX emissions results from paragraph (r)(1) of this section 
plus the CO emissions results from paragraph (r)(2) of this section.
    (s) Affirmative defense for exceedance of emissions limit during 
malfunction. In response to an action to enforce the standards set 
forth in paragraph Sec. Sec.  60.42Da, 60.43Da, 60.44Da, and 60.45Da, 
you may assert an affirmative defense to a claim for civil penalties 
for exceedances of such standards that are caused by malfunction, as 
defined at 40 CFR 60.2. Appropriate penalties may be assessed, however, 
if you fail to meet your burden of proving all of the requirements in 
the affirmative defense as specified in paragraphs (s)(1) and (2) of 
this section. The affirmative defense shall not be available for claims 
for injunctive relief.
    (1) To establish the affirmative defense in any action to enforce 
such a limit, you must timely meet the notification requirements in 
paragraph (s)(2) of this section, and must prove by a preponderance of 
evidence that:
    (i) The excess emissions:
    (A) Were caused by a sudden, infrequent, and unavoidable failure of 
air pollution control and monitoring equipment, process equipment, or a 
process to operate in a normal or usual manner; and
    (B) Could not have been prevented through careful planning, proper 
design, or better operation and maintenance practices; and
    (C) Did not stem from any activity or event that could have been 
foreseen and avoided, or planned for; and
    (D) Were not part of a recurring pattern indicative of inadequate 
design, operation, or maintenance; and
    (ii) Repairs were made as expeditiously as possible when the 
applicable emissions limits were being exceeded. Off-shift and overtime 
labor were used, to the extent practicable to make these repairs; and
    (iii) The frequency, amount, and duration of the excess emissions 
(including any bypass) were minimized to the maximum extent practicable 
during periods of such emissions; and
    (iv) If the excess emissions resulted from a bypass of control 
equipment or a process, then the bypass was unavoidable to prevent loss 
of life, personal injury, or severe property damage; and
    (v) All possible steps were taken to minimize the impact of the 
excess emissions on ambient air quality, the environment, and human 
health; and
    (vi) All emissions monitoring and control systems were kept in 
operation if at all possible, consistent with safety and good air 
pollution control practices; and
    (vii) All of the actions in response to the excess emissions were 
documented by properly signed, contemporaneous operating logs; and
    (viii) At all times, the facility was operated in a manner 
consistent with good practices for minimizing emissions; and
    (ix) A written root cause analysis has been prepared, the purpose 
of which is to determine, correct, and eliminate the primary causes of 
the malfunction and the excess emissions resulting from the malfunction 
event at issue. The analysis shall also specify, using best monitoring 
methods and engineering judgment, the amount of excess emissions that 
were the result of the malfunction.
    (2) Notification. The owner or operator of the affected source 
experiencing an exceedance of its emission limit(s) during a 
malfunction shall notify the Administrator by telephone or facsimile 
(FAX) transmission as soon as possible, but no later than two business 
days after the initial occurrence of the malfunction or, if it is not 
possible to determine within two business days whether the malfunction 
caused or contributed to an exceedance, no later than two business days 
after the owner or operator knew or should have known that the 
malfunction caused or contributed to an exceedance, but, in no event 
later than two business days after the end of the averaging period, if 
it wishes to avail itself of an affirmative defense to civil penalties 
for that malfunction. The owner or operator seeking to assert an 
affirmative defense shall also submit a written report to the 
Administrator within 45 days of the initial occurrence of the 
exceedance of the standard in Sec.  63.9991 to demonstrate, with all 
necessary supporting documentation, that it has met the requirements 
set forth in paragraph (s)(1) of this section. The owner or operator 
may seek an extension of this deadline for up to 30 additional days by 
submitting a written request to the Administrator before the expiration 
of the 45 day period. Until a request for an extension has been 
approved by the Administrator, the owner or operator is subject to the 
requirement to submit such report within 45 days of the initial 
occurrence of the exceedance.

0
19. Section 60.49Da is amended as follows:
0
a. By revising paragraphs (a)(1) and (2).

[[Page 9457]]

0
b. By revising paragraph (a)(3) introductory text.
0
c. By revising paragraph (a)(3)(ii).
0
d. By revising paragraph (a)(3)(iii)(B).
0
e. By adding paragraph (a)(4).
0
f. By revising paragraph (b) introductory text.
0
g. By revising paragraph (b)(2).
0
h. By revising paragraph (e).
0
i. By revising paragraph (k) introductory text.
0
j. By revising paragraph (k)(3).
0
k. By revising paragraph (l).
0
l. By removing and reserving paragraph (p).
0
m. By removing and reserving paragraph (q).
0
n. By removing and reserving paragraph (r).
0
o. By revising paragraph (t).
0
p. By revising paragraph (u)(1)(iii).
0
q. By revising paragraph (v)(4).


Sec.  60.49Da  Emission monitoring.

    (a) * * *
    (1) Except as provided for in paragraphs (a)(2) and (4) of this 
section, the owner or operator of an affected facility subject to an 
opacity standard, shall install, calibrate, maintain, and operate a 
COMS, and record the output of the system, for measuring the opacity of 
emissions discharged to the atmosphere. If opacity interference due to 
water droplets exists in the stack (for example, from the use of an FGD 
system), the opacity is monitored upstream of the interference (at the 
inlet to the FGD system). If opacity interference is experienced at all 
locations (both at the inlet and outlet of the SO2 control 
system), alternate parameters indicative of the PM control system's 
performance and/or good combustion are monitored (subject to the 
approval of the Administrator).
    (2) As an alternative to the monitoring requirements in paragraph 
(a)(1) of this section, an owner or operator of an affected facility 
that meets the conditions in either paragraph (a)(2)(i), (ii), (iii), 
or (iv) of this section may elect to monitor opacity as specified in 
paragraph (a)(3) of this section.
    (i) The affected facility uses a fabric filter (baghouse) to meet 
the standards in Sec.  60.42Da and a bag leak detection system is 
installed and operated according to the requirements in paragraphs 
Sec.  60.48Da(o)(4)(i) through (v);
    (ii) The affected facility burns only gaseous or liquid fuels 
(excluding residual oil) with potential SO2 emissions rates 
of 26 ng/J (0.060 lb/MMBtu) or less, and does not use a post-combustion 
technology to reduce emissions of SO2 or PM;
    (iii) The affected facility meets all of the conditions specified 
in paragraphs (a)(2)(iii)(A) through (C) of this section.
    (A) No post-combustion technology (except a wet scrubber) is used 
for reducing PM, SO2, or CO emissions;
    (B) Only natural gas, gaseous fuels, or fuel oils that contain less 
than or equal to 0.30 weight percent sulfur are burned; and
    (C) Emissions of CO discharged to the atmosphere are maintained at 
levels less than or equal to 1.4 lb/MWh on a boiler operating day 
average basis as demonstrated by the use of a CEMS measuring CO 
emissions according to the procedures specified in paragraph (u) of 
this section; or
    (iv) The affected facility uses an ESP and uses an ESP predictive 
model to monitor the performance of the ESP developed in accordance and 
operated according to the most current requirements in section Sec.  
60.48Da of this part.
    (3) The owner or operator of an affected facility that meets the 
conditions in paragraph (a)(2) of this section may, as an alternative 
to using a COMS, elect to monitor visible emissions using the 
applicable procedures specified in paragraphs (a)(3)(i) through (iv) of 
this section. The opacity performance test requirement in paragraph 
(a)(3)(i) must be conducted by April 29, 2011, within 45 days after 
stopping use of an existing COMS, or within 180 days after initial 
startup of the facility, whichever is later.
* * * * *
    (ii) Except as provided in paragraph (a)(3)(iii) or (iv) of this 
section, the owner or operator shall conduct subsequent Method 9 of 
appendix A-4 of this part performance tests using the procedures in 
paragraph (a)(3)(i) of this section according to the applicable 
schedule in paragraphs (a)(3)(ii)(A) through (a)(3)(ii)(C) of this 
section, as determined by the most recent Method 9 of appendix A-4 of 
this part performance test results.
    (A) If the maximum 6-minute average opacity is less than or equal 
to 5 percent, a subsequent Method 9 of appendix A-4 of this part 
performance test must be completed within 12 calendar months from the 
date that the most recent performance test was conducted or within 45 
days of the next day that fuel with an opacity standard is combusted, 
whichever is later;
    (B) If the maximum 6-minute average opacity is greater than 5 
percent but less than or equal to 10 percent, a subsequent Method 9 of 
appendix A-4 of this part performance test must be completed within 3 
calendar months from the date that the most recent performance test was 
conducted or within 45 days of the next day that fuel with an opacity 
standard is combusted, whichever is later; or
    (C) If the maximum 6-minute average opacity is greater than 10 
percent, a subsequent Method 9 of appendix A-4 of this part performance 
test must be completed within 45 calendar days from the date that the 
most recent performance test was conducted.
    (iii) * * *
    (B) If no visible emissions are observed for 10 operating days 
during which an opacity standard is applicable, observations can be 
reduced to once every 7 operating days during which an opacity standard 
is applicable. If any visible emissions are observed, daily 
observations shall be resumed.
* * * * *
    (4) An owner or operator of an affected facility that is subject to 
an opacity standard under Sec.  60.42a(b) is not required to operate a 
COMS provided that affected facility meets the conditions in either 
paragraph (a)(4)(i) or (ii) of this section.
    (i) The affected facility combusts only gaseous fuels and/or liquid 
fuels (excluding residue oil) with a potential SO2 emissions 
rate no greater than 26 ng/J (0.060 lb/MMBtu), and the unit operates 
according to a written site-specific monitoring plan approved by the 
permitting authority. This monitoring plan must include procedures and 
criteria for establishing and monitoring specific parameters for the 
affected facility indicative of compliance with the opacity standard. 
For testing performed as part of this site-specific monitoring plan, 
the permitting authority may require as an alternative to the 
notification and reporting requirements specified in Sec. Sec.  60.8 
and 60.11 that the owner or operator submit any deviations with the 
excess emissions report required under Sec.  60.51a(d).
    (ii) The owner or operator of the affected facility installs, 
calibrates, operates, and maintains a particulate matter continuous 
parametric monitoring system (PM CPMS) according to the requirements 
specified in subpart UUUUU of part 63.
    (b) The owner or operator of an affected facility shall install, 
calibrate, maintain, and operate a CEMS, and record the output of the 
system, for measuring SO2 emissions, except where natural 
gas and/or liquid fuels (excluding residual oil) with potential 
SO2 emissions rates of 26 ng/J (0.060 lb/

[[Page 9458]]

MMBtu) or less are the only fuels combusted, as follows:
* * * * *
    (2) For a facility that qualifies under the numerical limit 
provisions of Sec.  60.43Da, SO2 emissions are only 
monitored as discharged to the atmosphere.
* * * * *
    (e) The CEMS under paragraphs (b), (c), and (d) of this section are 
operated and data recorded during all periods of operation of the 
affected facility including periods of startup, shutdown, and 
malfunction, except for CEMS breakdowns, repairs, calibration checks, 
and zero and span adjustments.
* * * * *
    (k) The procedures specified in paragraphs (k)(1) through (3) of 
this section shall be used to determine gross energy output for sources 
demonstrating compliance with an output-based standard.
* * * * *
    (3) For an affected facility generating process steam in 
combination with electrical generation, the gross energy output is 
determined according to the definition of ``gross energy output'' 
specified in Sec.  60.41Da that is applicable to the affected facility.
    (l) The owner or operator of an affected facility demonstrating 
compliance with an output-based standard shall install, certify, 
operate, and maintain a continuous flow monitoring system meeting the 
requirements of Performance Specification 6 of appendix B of this part 
and the calibration drift (CD) assessment, relative accuracy test audit 
(RATA), and reporting provisions of procedure 1 of appendix F of this 
part, and record the output of the system, for measuring the volumetric 
flow rate of exhaust gases discharged to the atmosphere; or
* * * * *
    (t) The owner or operator of an affected facility demonstrating 
compliance with the output-based emissions limitation under Sec.  
60.42Da shall install, certify, operate, and maintain a CEMS for 
measuring PM emissions according to the requirements of paragraph (v) 
of this section. An owner or operator of an affected facility 
demonstrating compliance with the input-based emissions limit in Sec.  
60.42Da may install, certify, operate, and maintain a CEMS for 
measuring PM emissions according to the requirements of paragraph (v) 
of this section.
    (u) * * *
    (1) * * *
    (iii) At a minimum, non-out-of-control 1-hour CO emissions averages 
must be obtained for at least 90 percent of the operating hours on a 
30-boiler operating day rolling average basis. The 1-hour averages are 
calculated using the data points required in Sec.  60.13(h)(2).
* * * * *
    (v) * * *
    (4) As of January 1, 2012, and within 90 days after the date of 
completing each performance test, as defined in Sec.  60.8, conducted 
to demonstrate compliance with this subpart, you must submit relative 
accuracy test audit (i.e., reference method) data and performance test 
(i.e., compliance test) data, except opacity data, electronically to 
EPA's Central Data Exchange (CDX) by using the Electronic Reporting 
Tool (ERT) (see http://www.epa.gov/ttn/chief/ert/ert tool.html/) or 
other compatible electronic spreadsheet. Only data collected using test 
methods compatible with ERT are subject to this requirement to be 
submitted electronically into EPA's WebFire database.
* * * * *

0
20. Section 60.50Da is amended as follows:
0
a. By revising paragraph (b).
0
b. By removing paragraph (g).
0
c. By removing paragraph (h).
0
d. By removing paragraph (i).


Sec.  60.50Da  Compliance determination procedures and methods.

* * * * *
    (b) In conducting the performance tests to determine compliance 
with the PM emissions limits in Sec.  60.42Da, the owner or operator 
shall meet the requirements specified in paragraphs (b)(1) through (3) 
of this section.
    (1) The owner or operator shall measure filterable PM to determine 
compliance with the applicable PM emissions limit in Sec.  60.42Da as 
specified in paragraphs (b)(1)(i) through (ii) of this section.
    (i) The dry basis F factor (O2) procedures in Method 19 
of appendix A of this part shall be used to compute the emission rate 
of PM.
    (ii) For the PM concentration, Method 5 of appendix A of this part 
shall be used for an affected facility that does not use a wet FGD. For 
an affected facility that uses a wet FGD, Method 5B of appendix A of 
this part shall be used downstream of the wet FGD.
    (A) The sampling time and sample volume for each run shall be at 
least 120 minutes and 1.70 dscm (60 dscf). The probe and filter holder 
heating system in the sampling train may be set to provide an average 
gas temperature of no greater than 160  14 [deg]C (320 
 25[emsp14][deg]F).
    (B) For each particulate run, the emission rate correction factor, 
integrated or grab sampling and analysis procedures of Method 3B of 
appendix A of this part shall be used to determine the O2 
concentration. The O2 sample shall be obtained 
simultaneously with, and at the same traverse points as, the 
particulate run. If the particulate run has more than 12 traverse 
points, the O2 traverse points may be reduced to 12 provided 
that Method 1 of appendix A of this part is used to locate the 12 
O2 traverse points. If the grab sampling procedure is used, 
the O2 concentration for the run shall be the arithmetic 
mean of the sample O2 concentrations at all traverse points.
    (2) In conjunction with a performance test performed according to 
the requirements in paragraph (b)(1) of this section, the owner or 
operator of an affected facility for which construction, 
reconstruction, or modification commenced after May 3, 2011, shall 
measure condensable PM using Method 202 of appendix M of part 51.
    (3) Method 9 of appendix A of this part and the procedures in Sec.  
60.11 shall be used to determine opacity.
* * * * *
0
21. Section 60.51Da is amended as follows:
0
a. By revising paragraph (a).
0
b. By revising paragraph (b)(5).
0
c. By revising paragraph (d).
0
d. By removing and reserving paragraph (g).
0
e. By revising paragraph (k).


Sec.  60.51Da  Reporting requirements.

    (a) For SO2, NOX, PM, and NOX plus 
CO emissions, the performance test data from the initial and subsequent 
performance test and from the performance evaluation of the continuous 
monitors (including the transmissometer) must be reported to the 
Administrator.
    (b) * * *
    (5) Identification of the times when emissions data have been 
excluded from the calculation of average emission rates because of 
startup, shutdown, or malfunction.
* * * * *
    (d) In addition to the applicable requirements in Sec.  60.7, the 
owner or operator of an affected facility subject to the opacity limits 
in Sec.  60.43c(c) and conducting performance tests using Method 9 of 
appendix A-4 of this part shall submit excess emission reports for any 
excess emissions from the affected facility that occur during the 
reporting period and maintain records according to the requirements 
specified in paragraph (d)(1) of this section.
    (1) For each performance test conducted using Method 9 of appendix

[[Page 9459]]

A-4 of this part, the owner or operator shall keep the records 
including the information specified in paragraphs (d)(1)(i) through 
(iii) of this section.
    (i) Dates and time intervals of all opacity observation periods;
    (ii) Name, affiliation, and copy of current visible emission 
reading certification for each visible emission observer participating 
in the performance test; and
    (iii) Copies of all visible emission observer opacity field data 
sheets.
    (2) [Reserved]
* * * * *
    (k) The owner or operator of an affected facility may submit 
electronic quarterly reports for SO2 and/or NOX 
and/or opacity in lieu of submitting the written reports required under 
paragraphs (b) and (i) of this section. The format of each quarterly 
electronic report shall be coordinated with the permitting authority. 
The electronic report(s) shall be submitted no later than 30 days after 
the end of the calendar quarter and shall be accompanied by a 
certification statement from the owner or operator, indicating whether 
compliance with the applicable emission standards and minimum data 
requirements of this subpart was achieved during the reporting period.


Sec.  60.52Da  [Amended]

0
22. Section 60.52Da is amended by removing and reserving paragraph (a).

Subpart Db--[Amended]

0
23. Section 60.40b is amended as follows:
0
a. By revising paragraph (c).
0
b. By revising paragraph (h).
0
c. By revising paragraph (i).
0
d. By adding paragraph (1).
0
e. By adding paragraph (m).


Sec.  60.40b  Applicability and delegation of authority.

* * * * *
    (c) Affected facilities that also meet the applicability 
requirements under subpart J or subpart Ja of this part are subject to 
the PM and NOX standards under this subpart and the 
SO2 standards under subpart J or subpart Ja of this part, as 
applicable.
* * * * *
    (h) Any affected facility that meets the applicability requirements 
and is subject to subpart Ea, subpart Eb, subpart AAAA, or subpart CCCC 
of this part is not subject to this subpart.
    (i) Affected facilities (i.e., heat recovery steam generators) that 
are associated with stationary combustion turbines and that meet the 
applicability requirements of subpart KKKK of this part are not subject 
to this subpart. This subpart will continue to apply to all other 
affected facilities (i.e. heat recovery steam generators with duct 
burners) that are capable of combusting more than 29 MW (100 MMBtu/h) 
heat input of fossil fuel. If the affected facility (i.e. heat recovery 
steam generator) is subject to this subpart, only emissions resulting 
from combustion of fuels in the steam generating unit are subject to 
this subpart. (The stationary combustion turbine emissions are subject 
to subpart GG or KKKK, as applicable, of this part.)
* * * * *
    (l) Affected facilities that also meet the applicability 
requirements under subpart BB of this part (Standards of Performance 
for Kraft Pulp Mills) are subject to the SO2 and 
NOX standards under this subpart and the PM standards under 
subpart BB.
    (m) Temporary boilers are not subject to this subpart.
    24. Section 60.41b is amended by revising the definition of 
``distillate oil'', and adding the definition of ``temporary boiler'' 
in alphabetical order to read as follows:


Sec.  60.41b  Definitions.

* * * * *
    Distillate oil means fuel oils that contain 0.05 weight percent 
nitrogen or less and comply with the specifications for fuel oil 
numbers 1 and 2, as defined by the American Society of Testing and 
Materials in ASTM D396 (incorporated by reference, see Sec.  60.17), 
diesel fuel oil numbers 1 and 2, as defined by the American Society for 
Testing and Materials in ASTM D975 (incorporated by reference, see 
Sec.  60.17), kerosine, as defined by the American Society of Testing 
and Materials in ASTM D3699 (incorporated by reference, see Sec.  
60.17), biodiesel as defined by the American Society of Testing and 
Materials in ASTM D6751 (incorporated by reference, see Sec.  60.17), 
or biodiesel blends as defined by the American Society of Testing and 
Materials in ASTM D7467 (incorporated by reference, see Sec.  60.17).
* * * * *
    Temporary boiler means any gaseous or liquid fuel-fired steam 
generating unit that is designed to, and is capable of, being carried 
or moved from one location to another by means of, for example, wheels, 
skids, carrying handles, dollies, trailers, or platforms. A steam 
generating unit is not a temporary boiler if any one of the following 
conditions exists:
    (1) The equipment is attached to a foundation.
    (2) The steam generating unit or a replacement remains at a 
location for more than 180 consecutive days. Any temporary boiler that 
replaces a temporary boiler at a location and performs the same or 
similar function will be included in calculating the consecutive time 
period.
    (3) The equipment is located at a seasonal facility and operates 
during the full annual operating period of the seasonal facility, 
remains at the facility for at least 2 years, and operates at that 
facility for at least 3 months each year.
    (4) The equipment is moved from one location to another in an 
attempt to circumvent the residence time requirements of this 
definition.
* * * * *
0
25. Section 60.43b is amended by revising paragraph (f) to read as 
follows:


Sec.  60.43b  Standard for particulate matter (PM).

* * * * *
    (f) On and after the date on which the initial performance test is 
completed or is required to be completed under Sec.  60.8, whichever 
date comes first, no owner or operator of an affected facility that 
combusts coal, oil, wood, or mixtures of these fuels with any other 
fuels shall cause to be discharged into the atmosphere any gases that 
exhibit greater than 20 percent opacity (6-minute average), except for 
one 6-minute period per hour of not more than 27 percent opacity. An 
owner or operator of an affected facility that elects to install, 
calibrate, maintain, and operate a continuous emissions monitoring 
system (CEMS) for measuring PM emissions according to the requirements 
of this subpart and is subject to a federally enforceable PM limit of 
0.030 lb/MMBtu or less is exempt from the opacity standard specified in 
this paragraph.
* * * * *
0
26. Section 60.44b is amended as follows:
0
a. The section heading is revised.
0
b. By revising paragraph (b) introductory text.
0
c. By revising paragraph (c).
0
d. By revising paragraph (d).
0
e. By revising paragraph (e).
0
f. By revising paragraph (l)(1).


Sec.  60.44b  Standard for nitrogen oxides (NOX).

* * * * *
    (b) Except as provided under paragraphs (k) and (l) of this 
section, on and after the date on which the initial performance test is 
completed or is required to be completed under Sec.  60.8, whichever 
date comes first, no owner or operator of an affected facility that

[[Page 9460]]

simultaneously combusts mixtures of only coal, oil, or natural gas 
shall cause to be discharged into the atmosphere from that affected 
facility any gases that contain NOX in excess of a limit 
determined by the use of the following formula:
* * * * *
    (c) Except as provided under paragraph (d) and (l) of this section, 
on and after the date on which the initial performance test is 
completed or is required to be completed under Sec.  60.8, whichever 
date comes first, no owner or operator of an affected facility that 
simultaneously combusts coal or oil, natural gas (or any combination of 
the three), and wood, or any other fuel shall cause to be discharged 
into the atmosphere any gases that contain NOX in excess of 
the emission limit for the coal, oil, natural gas (or any combination 
of the three), combusted in the affected facility, as determined 
pursuant to paragraph (a) or (b) of this section. This standard does 
not apply to an affected facility that is subject to and in compliance 
with a federally enforceable requirement that limits operation of the 
affected facility to an annual capacity factor of 10 percent (0.10) or 
less for coal, oil, natural gas (or any combination of the three).
    (d) On and after the date on which the initial performance test is 
completed or is required to be completed under Sec.  60.8, whichever 
date comes first, no owner or operator of an affected facility that 
simultaneously combusts natural gas and/or distillate oil with a 
potential SO2 emissions rate of 26 ng/J (0.060 lb/MMBtu) or 
less with wood, municipal-type solid waste, or other solid fuel, except 
coal, shall cause to be discharged into the atmosphere from that 
affected facility any gases that contain NOX in excess of 
130 ng/J (0.30 lb/MMBtu) heat input unless the affected facility has an 
annual capacity factor for natural gas, distillate oil, or a mixture of 
these fuels of 10 percent (0.10) or less and is subject to a federally 
enforceable requirement that limits operation of the affected facility 
to an annual capacity factor of 10 percent (0.10) or less for natural 
gas, distillate oil, or a mixture of these fuels.
    (e) Except as provided under paragraph (l) of this section, on and 
after the date on which the initial performance test is completed or is 
required to be completed under Sec.  60.8, whichever date comes first, 
no owner or operator of an affected facility that simultaneously 
combusts only coal, oil, or natural gas with byproduct/waste shall 
cause to be discharged into the atmosphere any gases that contain 
NOX in excess of the emission limit determined by the 
following formula unless the affected facility has an annual capacity 
factor for coal, oil, and natural gas of 10 percent (0.10) or less and 
is subject to a federally enforceable requirement that limits operation 
of the affected facility to an annual capacity factor of 10 percent 
(0.10) or less:
* * * * *
    (l) * * *
    (1) 86 ng/J (0.20 lb/MMBtu) heat input if the affected facility 
combusts coal, oil, or natural gas (or any combination of the three), 
alone or with any other fuels. The affected facility is not subject to 
this limit if it is subject to and in compliance with a federally 
enforceable requirement that limits operation of the facility to an 
annual capacity factor of 10 percent (0.10) or less for coal, oil, and 
natural gas (or any combination of the three); or
* * * * *
0
27. Section 60.46b is amended by revising paragraph (j)(14) to read as 
follows:


Sec.  60.46b  Compliance and performance test methods and procedures 
for particulate matter and nitrogen oxides.

* * * * *
    (j) * * *
    (14) As of January 1, 2012, and within 90 days after the date of 
completing each performance test, as defined in Sec.  60.8, conducted 
to demonstrate compliance with this subpart, you must submit relative 
accuracy test audit (i.e., reference method) data and performance test 
(i.e., compliance test) data, except opacity data, electronically to 
EPA's Central Data Exchange (CDX) by using the Electronic Reporting 
Tool (ERT) (see http://www.epa.gov/ttn/chief/ert/ert_tool.html/) or 
other compatible electronic spreadsheet. Only data collected using test 
methods compatible with ERT are subject to this requirement to be 
submitted electronically into EPA's WebFIRE database.
0
28. Section 60.48b is amended as follows:
0
a. By revising paragraph (a) introductory text.
0
b. By revising paragraphs (a)(1)(i) through (iii) .
0
c. By revising paragraph (a)(2)(ii).
0
d. By revising paragraph (j) introductory text.
0
e. By revising paragraph (j)(5).
0
f. By revising paragraph (j)(6).
0
g. By adding paragraph (j)(7).
0
h. By adding paragraph (l).


Sec.  60.48b  Emission monitoring for particulate matter and nitrogen 
oxides.

    (a) Except as provided in paragraph (j) of this section, the owner 
or operator of an affected facility subject to the opacity standard 
under Sec.  60.43b shall install, calibrate, maintain, and operate a 
continuous opacity monitoring systems (COMS) for measuring the opacity 
of emissions discharged to the atmosphere and record the output of the 
system. The owner or operator of an affected facility subject to an 
opacity standard under Sec.  60.43b and meeting the conditions under 
paragraphs (j)(1), (2), (3), (4), (5), or (6) of this section who 
elects not to use a COMS shall conduct a performance test using Method 
9 of appendix A-4 of this part and the procedures in Sec.  60.11 to 
demonstrate compliance with the applicable limit in Sec.  60.43b by 
April 29, 2011, within 45 days of stopping use of an existing COMS, or 
within 180 days after initial startup of the facility, whichever is 
later, and shall comply with either paragraphs (a)(1), (a)(2), or 
(a)(3) of this section. The observation period for Method 9 of appendix 
A-4 of this part performance tests may be reduced from 3 hours to 60 
minutes if all 6-minute averages are less than 10 percent and all 
individual 15-second observations are less than or equal to 20 percent 
during the initial 60 minutes of observation.
    (1) * * *
    (i) If no visible emissions are observed, a subsequent Method 9 of 
appendix A-4 of this part performance test must be completed within 12 
calendar months from the date that the most recent performance test was 
conducted or within 45 days of the next day that fuel with an opacity 
standard is combusted, whichever is later;
    (ii) If visible emissions are observed but the maximum 6-minute 
average opacity is less than or equal to 5 percent, a subsequent Method 
9 of appendix A-4 of this part performance test must be completed 
within 6 calendar months from the date that the most recent performance 
test was conducted or within 45 days of the next day that fuel with an 
opacity standard is combusted, whichever is later;
    (iii) If the maximum 6-minute average opacity is greater than 5 
percent but less than or equal to 10 percent, a subsequent Method 9 of 
appendix A-4 of this part performance test must be completed within 3 
calendar months from the date that the most recent performance test was 
conducted or within 45 days of the next day that fuel with an opacity 
standard is combusted, whichever is later; or
* * * * *
    (2) * * *
    (ii) If no visible emissions are observed for 10 operating days 
during which an opacity standard is applicable, observations can be 
reduced to once every 7 operating days during which an

[[Page 9461]]

opacity standard is applicable. If any visible emissions are observed, 
daily observations shall be resumed.
* * * * *
    (j) The owner or operator of an affected facility that meets the 
conditions in either paragraph (j)(1), (2), (3), (4), (5), (6), or (7) 
of this section is not required to install or operate a COMS if:
* * * * *
    (5) The affected facility uses a bag leak detection system to 
monitor the performance of a fabric filter (baghouse) according to the 
most current requirements in section Sec.  60.48Da of this part; or
    (6) The affected facility uses an ESP as the primary PM control 
device and uses an ESP predictive model to monitor the performance of 
the ESP developed in accordance and operated according to the most 
current requirements in section Sec.  60.48Da of this part; or
    (7) The affected facility burns only gaseous fuels or fuel oils 
that contain less than or equal to 0.30 weight percent sulfur and 
operates according to a written site-specific monitoring plan approved 
by the permitting authority. This monitoring plan must include 
procedures and criteria for establishing and monitoring specific 
parameters for the affected facility indicative of compliance with the 
opacity standard.
* * * * *
    (l) An owner or operator of an affected facility that is subject to 
an opacity standard under Sec.  60.43b(f) is not required to operate a 
COMS provided that the unit burns only gaseous fuels and/or liquid 
fuels (excluding residue oil) with a potential SO2 emissions 
rate no greater than 26 ng/J (0.060 lb/MMBtu), and the unit operates 
according to a written site-specific monitoring plan approved by the 
permitting authority is not required to operate a COMS. This monitoring 
plan must include procedures and criteria for establishing and 
monitoring specific parameters for the affected facility indicative of 
compliance with the opacity standard. For testing performed as part of 
this site-specific monitoring plan, the permitting authority may 
require as an alternative to the notification and reporting 
requirements specified in Sec. Sec.  60.8 and 60.11 that the owner or 
operator submit any deviations with the excess emissions report 
required under Sec.  60.49b(h).
0
29. Section 60.49b is amended by revising paragraph (r)(1) to read as 
follows.


Sec.  60.49b  Reporting and recordkeeping requirements.

* * * * *
    (r) * * *
    (1) The owner or operator of an affected facility who elects to 
demonstrate that the affected facility combusts only very low sulfur 
oil, natural gas, wood, a mixture of these fuels, or any of these fuels 
(or a mixture of these fuels) in combination with other fuels that are 
known to contain an insignificant amount of sulfur in Sec.  60.42b(j) 
or Sec.  60.42b(k) shall obtain and maintain at the affected facility 
fuel receipts (such as a current, valid purchase contract, tariff 
sheet, or transportation contract) from the fuel supplier that certify 
that the oil meets the definition of distillate oil and gaseous fuel 
meets the definition of natural gas as defined in Sec.  60.41b and the 
applicable sulfur limit. For the purposes of this section, the 
distillate oil need not meet the fuel nitrogen content specification in 
the definition of distillate oil. Reports shall be submitted to the 
Administrator certifying that only very low sulfur oil meeting this 
definition, natural gas, wood, and/or other fuels that are known to 
contain insignificant amounts of sulfur were combusted in the affected 
facility during the reporting period; or
* * * * *

Subpart Dc--[Amended]

0
30. Section 60.40c is amended as follows:
0
a. By revising paragraph (a).
0
b. By revising paragraph (e).
0
c. By revising paragraph (f).
0
d. By revising paragraph (g).
0
e. By adding paragraph (h).
0
f. By adding paragraph (i).


Sec.  60.40c  Applicability and delegation of authority.

    (a) Except as provided in paragraphs (d), (e), (f), and (g) of this 
section, the affected facility to which this subpart applies is each 
steam generating unit for which construction, modification, or 
reconstruction is commenced after June 9, 1989 and that has a maximum 
design heat input capacity of 29 megawatts (MW) (100 million British 
thermal units per hour (MMBtu/h)) or less, but greater than or equal to 
2.9 MW (10 MMBtu/h).
* * * * *
    (e) Affected facilities (i.e. heat recovery steam generators and 
fuel heaters) that are associated with stationary combustion turbines 
and meet the applicability requirements of subpart KKKK of this part 
are not subject to this subpart. This subpart will continue to apply to 
all other heat recovery steam generators, fuel heaters, and other 
affected facilities that are capable of combusting more than or equal 
to 2.9 MW (10 MMBtu/h) heat input of fossil fuel but less than or equal 
to 29 MW (100 MMBtu/h) heat input of fossil fuel. If the heat recovery 
steam generator, fuel heater, or other affected facility is subject to 
this subpart, only emissions resulting from combustion of fuels in the 
steam generating unit are subject to this subpart. (The stationary 
combustion turbine emissions are subject to subpart GG or KKKK, as 
applicable, of this part.)
    (f) Any affected facility that meets the applicability requirements 
of and is subject to subpart AAAA or subpart CCCC of this part is not 
subject to this subpart.
    (g) Any facility that meets the applicability requirements and is 
subject to an EPA approved State or Federal section 111(d)/129 plan 
implementing subpart BBBB of this part is not subject to this subpart.
    (h) Affected facilities that also meet the applicability 
requirements under subpart J or subpart Ja of this part are subject to 
the PM and NOX standards under this subpart and the 
SO2 standards under subpart J or subpart Ja of this part, as 
applicable.
    (i) Temporary boilers are not subject to this subpart.
0
31. Section 60.41c is amended as follows:
0
a. By removing the definition of ``Cogeneration.''
0
b. By revising the definition of ``Distillate oil.''
0
c. By adding a definition of ``Temporary boiler'' in alphabetical 
order.


Sec.  60.41c  Definitions.

* * * * *
    Distillate oil means fuel oil that complies with the specifications 
for fuel oil numbers 1 or 2, as defined by the American Society for 
Testing and Materials in ASTM D396 (incorporated by reference, see 
Sec.  60.17), diesel fuel oil numbers 1 or 2, as defined by the 
American Society for Testing and Materials in ASTM D975 (incorporated 
by reference, see Sec.  60.17), kerosine, as defined by the American 
Society of Testing and Materials in ASTM D3699 (incorporated by 
reference, see Sec.  60.17), biodiesel as defined by the American 
Society of Testing and Materials in ASTM D6751 (incorporated by 
reference, see Sec.  60.17), or biodiesel blends as defined by the 
American Society of Testing and Materials in ASTM D7467 (incorporated 
by reference, see Sec.  60.17).
* * * * *

[[Page 9462]]

    Temporary boiler means a steam generating unit that combusts 
natural gas or distillate oil with a potential SO2 emissions 
rate no greater than 26 ng/J (0.060 lb/MMBtu), and the unit is designed 
to, and is capable of, being carried or moved from one location to 
another by means of, for example, wheels, skids, carrying handles, 
dollies, trailers, or platforms. A steam generating unit is not a 
temporary boiler if any one of the following conditions exists:
    (1) The equipment is attached to a foundation.
    (2) The steam generating unit or a replacement remains at a 
location for more than 180 consecutive days. Any temporary boiler that 
replaces a temporary boiler at a location and performs the same or 
similar function will be included in calculating the consecutive time 
period.
    (3) The equipment is located at a seasonal facility and operates 
during the full annual operating period of the seasonal facility, 
remains at the facility for at least 2 years, and operates at that 
facility for at least 3 months each year.
    (4) The equipment is moved from one location to another in an 
attempt to circumvent the residence time requirements of this 
definition.
* * * * *
0
32. Section 60.42c is amended as follows:
0
a. By revising paragraph (c)(1) and (3).
0
b. By revising paragraph (d).
0
c. By revising paragraph (e)(1)(ii).
0
d. By revising paragraph (h) introductory text.
0
e. By revising paragraph (h)(3).
0
f. By adding paragraph (h)(4).


Sec.  60.42c  Standard for sulfur dioxide (SO2).

* * * * *
    (c) * * *
    (1) Affected facilities that have a heat input capacity of 22 MW 
(75 MMBtu/h) or less;
* * * * *
    (3) Affected facilities located in a noncontinental area; or
* * * * *
    (d) On and after the date on which the initial performance test is 
completed or required to be completed under Sec.  60.8, whichever date 
comes first, no owner or operator of an affected facility that combusts 
oil shall cause to be discharged into the atmosphere from that affected 
facility any gases that contain SO2 in excess of 215 ng/J 
(0.50 lb/MMBtu) heat input from oil; or, as an alternative, no owner or 
operator of an affected facility that combusts oil shall combust oil in 
the affected facility that contains greater than 0.5 weight percent 
sulfur. The percent reduction requirements are not applicable to 
affected facilities under this paragraph.
    (e) * * *
    (1) * * *
    (ii) Has a heat input capacity greater than 22 MW (75 MMBtu/h); and
* * * * *
    (h) For affected facilities listed under paragraphs (h)(1), (2), 
(3), or (4) of this section, compliance with the emission limits or 
fuel oil sulfur limits under this section may be determined based on a 
certification from the fuel supplier, as described under Sec.  
60.48c(f), as applicable.
* * * * *
    (3) Coal-fired affected facilities with heat input capacities 
between 2.9 and 8.7 MW (10 and 30 MMBtu/h).
    (4) Other fuels-fired affected facilities with heat input 
capacities between 2.9 and 8.7 MW (10 and 30 MMBtu/h).
* * * * *

0
33. Section 60.43c is amended as follows:
0
a. By revising paragraph (a) introductory text.
0
b. By revising paragraph (b) introductory text.
0
c. By revising paragraph (c).
0
d. By revising paragraphs (e)(1), (3), and (4).


Sec.  60.43c  Standard for particulate matter (PM).

    (a) On and after the date on which the initial performance test is 
completed or required to be completed under Sec.  60.8, whichever date 
comes first, no owner or operator of an affected facility that 
commenced construction, reconstruction, or modification on or before 
February 28, 2005, that combusts coal or combusts mixtures of coal with 
other fuels and has a heat input capacity of 8.7 MW (30 MMBtu/h) or 
greater, shall cause to be discharged into the atmosphere from that 
affected facility any gases that contain PM in excess of the following 
emission limits:
* * * * *
    (b) On and after the date on which the initial performance test is 
completed or required to be completed under Sec.  60.8, whichever date 
comes first, no owner or operator of an affected facility that 
commenced construction, reconstruction, or modification on or before 
February 28, 2005, that combusts wood or combusts mixtures of wood with 
other fuels (except coal) and has a heat input capacity of 8.7 MW (30 
MMBtu/h) or greater, shall cause to be discharged into the atmosphere 
from that affected facility any gases that contain PM in excess of the 
following emissions limits:
* * * * *
    (c) On and after the date on which the initial performance test is 
completed or required to be completed under Sec.  60.8, whichever date 
comes first, no owner or operator of an affected facility that combusts 
coal, wood, or oil and has a heat input capacity of 8.7 MW (30 MMBtu/h) 
or greater shall cause to be discharged into the atmosphere from that 
affected facility any gases that exhibit greater than 20 percent 
opacity (6-minute average), except for one 6-minute period per hour of 
not more than 27 percent opacity. Owners and operators of an affected 
facility that elect to install, calibrate, maintain, and operate a 
continuous emissions monitoring system (CEMS) for measuring PM 
emissions according to the requirements of this subpart and are subject 
to a federally enforceable PM limit of 0.030 lb/MMBtu or less are 
exempt from the opacity standard specified in this paragraph (c).
* * * * *
    (e)(1) On and after the date on which the initial performance test 
is completed or is required to be completed under Sec.  60.8, whichever 
date comes first, no owner or operator of an affected facility that 
commences construction, reconstruction, or modification after February 
28, 2005, and that combusts coal, oil, wood, a mixture of these fuels, 
or a mixture of these fuels with any other fuels and has a heat input 
capacity of 8.7 MW (30 MMBtu/h) or greater shall cause to be discharged 
into the atmosphere from that affected facility any gases that contain 
PM in excess of 13 ng/J (0.030 lb/MMBtu) heat input, except as provided 
in paragraphs (e)(2), (e)(3), and (e)(4) of this section.
* * * * *
    (3) On and after the date on which the initial performance test is 
completed or is required to be completed under Sec.  60.8, whichever 
date comes first, no owner or operator of an affected facility that 
commences modification after February 28, 2005, and that combusts over 
30 percent wood (by heat input) on an annual basis and has a heat input 
capacity of 8.7 MW (30 MMBtu/h) or greater shall cause to be discharged 
into the atmosphere from that affected facility any gases that contain 
PM in excess of 43 ng/J (0.10 lb/MMBtu) heat input.
    (4) An owner or operator of an affected facility that commences 
construction, reconstruction, or modification after February 28, 2005, 
and that combusts only oil that contains no more than 0.50 weight 
percent sulfur

[[Page 9463]]

or a mixture of 0.50 weight percent sulfur oil with other fuels not 
subject to a PM standard under Sec.  60.43c and not using a post-
combustion technology (except a wet scrubber) to reduce PM or 
SO2 emissions is not subject to the PM limit in this 
section.

0
34. Section 60.45c is amended as follows:
0
a. By revising paragraph (c)(14).
0
b. By revising paragraph (d).


Sec.  60.45c  Compliance and performance test methods and procedures 
for particulate matter.

* * * * *
    (c) * * *
    (14) As of January 1, 2012, and within 90 days after the date of 
completing each performance test, as defined in Sec.  60.8, conducted 
to demonstrate compliance with this subpart, you must submit relative 
accuracy test audit (i.e., reference method) data and performance test 
(i.e., compliance test) data, except opacity data, electronically to 
EPA's Central Data Exchange (CDX) by using the Electronic Reporting 
Tool (ERT) (see http://www.epa.gov/ttn/chief/ert/ert tool.html/) or 
other compatible electronic spreadsheet. Only data collected using test 
methods compatible with ERT are subject to this requirement to be 
submitted electronically into EPA's WebFIRE database.
    (d) The owner or operator of an affected facility seeking to 
demonstrate compliance under Sec.  60.43c(e)(4) shall follow the 
applicable procedures under Sec.  60.48c(f). For residual oil-fired 
affected facilities, fuel supplier certifications are only allowed for 
facilities with heat input capacities between 2.9 and 8.7 MW (10 to 30 
MMBtu/h).

0
35. Section 60.47c is amended as follows:
0
a. By revising paragraph (a) introductory text.
0
b. By revising paragraphs (a)(1)(i) through (iii).
0
c. By revising paragraph (a)(2)(ii).
0
d. By revising paragraph (f).
0
e. By removing paragraph (g).


Sec.  60.47c  Emission monitoring for particulate matter.

    (a) Except as provided in paragraphs (c), (d), (e), and (f) of this 
section, the owner or operator of an affected facility combusting coal, 
oil, or wood that is subject to the opacity standards under Sec.  
60.43c shall install, calibrate, maintain, and operate a continuous 
opacity monitoring system (COMS) for measuring the opacity of the 
emissions discharged to the atmosphere and record the output of the 
system. The owner or operator of an affected facility subject to an 
opacity standard in Sec.  60.43c(c) that is not required to use a COMS 
due to paragraphs (c), (d), (e), or (f) of this section that elects not 
to use a COMS shall conduct a performance test using Method 9 of 
appendix A-4 of this part and the procedures in Sec.  60.11 to 
demonstrate compliance with the applicable limit in Sec.  60.43c by 
April 29, 2011, within 45 days of stopping use of an existing COMS, or 
within 180 days after initial startup of the facility, whichever is 
later, and shall comply with either paragraphs (a)(1), (a)(2), or 
(a)(3) of this section. The observation period for Method 9 of appendix 
A-4 of this part performance tests may be reduced from 3 hours to 60 
minutes if all 6-minute averages are less than 10 percent and all 
individual 15-second observations are less than or equal to 20 percent 
during the initial 60 minutes of observation.
    (1) * * *
    (i) If no visible emissions are observed, a subsequent Method 9 of 
appendix A-4 of this part performance test must be completed within 12 
calendar months from the date that the most recent performance test was 
conducted or within 45 days of the next day that fuel with an opacity 
standard is combusted, whichever is later;
    (ii) If visible emissions are observed but the maximum 6-minute 
average opacity is less than or equal to 5 percent, a subsequent Method 
9 of appendix A-4 of this part performance test must be completed 
within 6 calendar months from the date that the most recent performance 
test was conducted or within 45 days of the next day that fuel with an 
opacity standard is combusted, whichever is later;
    (iii) If the maximum 6-minute average opacity is greater than 5 
percent but less than or equal to 10 percent, a subsequent Method 9 of 
appendix A-4 of this part performance test must be completed within 3 
calendar months from the date that the most recent performance test was 
conducted or within 45 days of the next day that fuel with an opacity 
standard is combusted, whichever is later; or
* * * * *
    (2) * * *
    (ii) If no visible emissions are observed for 10 operating days 
during which an opacity standard is applicable, observations can be 
reduced to once every 7 operating days during which an opacity standard 
is applicable. If any visible emissions are observed, daily 
observations shall be resumed.
* * * * *
    (f) An owner or operator of an affected facility that is subject to 
an opacity standard in Sec.  60.43c(c) is not required to operate a 
COMS provided that the affected facility meets the conditions in either 
paragraphs (f)(1), (2), or (3) of this section.
    (1) The affected facility uses a fabric filter (baghouse) as the 
primary PM control device and, the owner or operator operates a bag 
leak detection system to monitor the performance of the fabric filter 
according to the requirements in section Sec.  60.48Da of this part.
    (2) The affected facility uses an ESP as the primary PM control 
device, and the owner or operator uses an ESP predictive model to 
monitor the performance of the ESP developed in accordance and operated 
according to the requirements in section Sec.  60.48Da of this part.
    (3) The affected facility burns only gaseous fuels and/or fuel oils 
that contain no greater than 0.5 weight percent sulfur, and the owner 
or operator operates the unit according to a written site-specific 
monitoring plan approved by the permitting authority. This monitoring 
plan must include procedures and criteria for establishing and 
monitoring specific parameters for the affected facility indicative of 
compliance with the opacity standard. For testing performed as part of 
this site-specific monitoring plan, the permitting authority may 
require as an alternative to the notification and reporting 
requirements specified in Sec. Sec.  60.8 and 60.11 that the owner or 
operator submit any deviations with the excess emissions report 
required under Sec.  60.48c(c).

Subpart HHHH--[Removed and Reserved]

0
36. Subpart HHHH is removed and reserved.

PART 63--[AMENDED]

0
37. The authority citation for 40 CFR Part 63 continues to read as 
follows:

    Authority: 42 U.S.C. 7401, et seq.

Subpart A--[Amended]

0
38. Section 63.14 is amended as follows:
0
a. By adding paragraphs (b)(19) and (20).
0
b. By adding paragraphs (b)(22) and (23).
0
c. By adding paragraphs (b)(69) through (72).
0
d. By revising paragraph (i)(1).


Sec.  63.14  Incorporation by reference.

* * * * *
    (b) * * *

[[Page 9464]]

    (19) ASTM D95-05 (Reapproved 2010), Standard Test Method for Water 
in Petroleum Products and Bituminous Materials by Distillation, 
approved May 1, 2010, IBR approved for Sec.  63.10005(i)(4)(i).
    (20) ASTM Method D388-05, Standard Classification of Coals by Rank, 
approved September 15, 2005, IBR approved for Sec.  63.10042.
* * * * *
    (22) ASTM Method D396-10, Standard Specification for Fuel Oils, 
including Appendix X1, approved October 1, 2010, IBR approved for Sec.  
63.10042.
    (23) ASTM D4006-11, Standard Test Method for Water in Crude Oil by 
Distillation, including Annex A1 and Appendix X1, approved June 1, 
2011, IBR approved for Sec.  63.10005(i)(4)(ii).
* * * * *
    (69) ASTM D4057-06 (Reapproved 2011), Standard Practice for Manual 
Sampling of Petroleum and Petroleum Products, including Annex A1, 
approved June 1, 2011, IBR approved for Sec.  63.10005(i)(4)(iv).
    (70) ASTM D4177-95 (Reapproved 2010), Standard Practice for 
Automatic Sampling of Petroleum and Petroleum Products, including 
Annexes A1 through A6 and Appendices X1 and X2, approved May 1, 2010, 
IBR approved for Sec.  63.10005(i)(4)(iii).
    (71) ASTM D6348-03 (Reapproved 2010), Standard Test Method for 
Determination of Gaseous Compounds by Extractive Direct Interface 
Fourier Transform Infrared (FTIR) Spectroscopy, including Annexes A1 
through A8, approved October 1, 2010, IBR approved for table 1 to 
subpart UUUUU of this part, table 2 to subpart UUUUU of this part, 
table 5 to subpart UUUUU of this part, and appendix B to subpart UUUUU 
of this part.
    (72) ASTM D6784-02 (Reapproved 2008), Standard Test Method for 
Elemental, Oxidized, Particle-Bound and Total Mercury in Flue Gas 
Generated from Coal-Fired Stationary Sources (Ontario Hydro Method), 
approved April 1, 2008, IBR approved for table 5 to subpart UUUUU of 
this part, and appendix A to subpart UUUUU of this part.
* * * * *
    (i) * * *
    (1) ANSI/ASME PTC 19.10-1981, ``Flue and Exhaust Gas Analyses [part 
10, Instruments and Apparatus],'' IBR approved for Sec. Sec.  
63.309(k)(1)(iii), 63.865(b), 63.3166(a)(3), 63.3360(e)(1)(iii), 
63.3545(a)(3), 63.3555(a)(3), 63.4166(a)(3), 63.4362(a)(3), 
63.4766(a)(3), 63.4965(a)(3), 63.5160(d)(1)(iii), 63.9307(c)(2), 
63.9323(a)(3), 63.11148(e)(3)(iii), 63.11155(e)(3), 63.11162(f)(3)(iii) 
and (f)(4), 63.11163(g)(1)(iii) and (g)(2), 63.11410(j)(1)(iii), 
63.11551(a)(2)(i)(C), table 5 to subpart DDDDD of this part, table 1 to 
subpart ZZZZZ of this part, table 4 to subpart JJJJJJ of this part, and 
table 5 to subpart UUUUU of this part.
* * * * *

0
39. Part 63 is amended by adding subpart UUUUU to read as follows:

Subpart UUUUU--National Emission Standards for Hazardous Air 
Pollutants: Coal- and Oil-Fired Electric Utility Steam Generating 
Units

Sec.

What This Subpart Covers

63.9980 What is the purpose of this subpart?
63.9981 Am I subject to this subpart?
63.9982 What is the affected source of this subpart?
63.9983 Are any EGUs not subject to this subpart?
63.9984 When do I have to comply with this subpart?
63.9985 What is a new EGU?

Emission Limitations and Work Practice Standards

63.9990 What are the subcategories of EGUs?
63.9991 What emission limitations, work practice standards, and 
operating limits must I meet?

General Compliance Requirements

63.10000 What are my general requirements for complying with this 
subpart?
63.10001 Affirmative defense for exceedence of emission limit during 
malfunction.

Testing and Initial Compliance Requirements

63.10005 What are my initial compliance requirements and by what 
date must I conduct them?
63.10006 When must I conduct subsequent performance tests or tune-
ups?
63.10007 What methods and other procedures must I use for the 
performance tests?
63.10008 [Reserved]
63.10009 May I use emissions averaging to comply with this subpart?
63.10010 What are my monitoring, installation, operation, and 
maintenance requirements?
63.10011 How do I demonstrate initial compliance with the emission 
limitations and work practice standards?

Continuous Compliance Requirements

63.10020 How do I monitor and collect data to demonstrate continuous 
compliance?
63.10021 How do I demonstrate continuous compliance with the 
emission limitations, operating limits, and work practice standards?
63.10022 How do I demonstrate continuous compliance under the 
emissions averaging provision?
63.10023 How do I establish my PM CPMS operating limit and determine 
compliance with it?

Notifications, Reports, and Records

63.10030 What notifications must I submit and when?
63.10031 What reports must I submit and when?
63.10032 What records must I keep?
63.10033 In what form and how long must I keep my records?

Other Requirements and Information

63.10040 What parts of the General Provisions apply to me?
63.10041 Who implements and enforces this subpart?
63.10042 What definitions apply to this subpart?

Tables to Subpart UUUUU of Part 63

Table 1 to Subpart UUUUU of Part 63--Emission Limits for New or 
Reconstructed EGUs
Table 2 to Subpart UUUUU of Part 63--Emission Limits for Existing 
EGUs
Table 3 to Subpart UUUUU of Part 63--Work Practice Standards
Table 4 to Subpart UUUUU of Part 63--Operating Limits for EGUs
Table 5 to Subpart UUUUU of Part 63--Performance Testing 
Requirements
Table 6 to Subpart UUUUU of Part 63--Establishing PM CPMS Operating 
Limits
Table 7 to Subpart UUUUU of Part 63--Demonstrating Continuous 
Compliance
Table 8 to Subpart UUUUU of Part 63--Reporting Requirements
Table 9 to Subpart UUUUU of Part 63--Applicability of General 
Provisions to Subpart UUUUU
Appendix A to Subpart UUUUU--Hg Monitoring Provisions
Appendix B to Subpart UUUUU--HCl and HF Monitoring Provisions

Subpart UUUUU--National Emission Standards for Hazardous Air 
Pollutants: Coal- and Oil-Fired Electric Utility Steam Generating 
Units

What This Subpart Covers


Sec.  63.9980  What is the purpose of this subpart?

    This subpart establishes national emission limitations and work 
practice standards for hazardous air pollutants (HAP) emitted from 
coal- and oil-fired electric utility steam generating units (EGUs) as 
defined in Sec.  63.10042 of this subpart. This subpart also 
establishes requirements to demonstrate initial and continuous 
compliance with the emission limitations.


Sec.  63.9981  Am I subject to this subpart?

    You are subject to this subpart if you own or operate a coal-fired 
EGU or an oil-fired EGU as defined in Sec.  63.10042 of this subpart.

[[Page 9465]]

Sec.  63.9982  What is the affected source of this subpart?

    (a) This subpart applies to each individual or group of two or more 
new, reconstructed, and existing affected source(s) as described in 
paragraphs (a)(1) and (2) of this section within a contiguous area and 
under common control.
    (1) The affected source of this subpart is the collection of all 
existing coal- or oil-fired EGUs, as defined in 63.10042, within a 
subcategory.
    (2) The affected source of this subpart is each new or 
reconstructed coal- or oil-fired EGU as defined in 63.10042.
    (b) An EGU is new if you commence construction of the coal- or oil-
fired EGU after May 3, 2011, and you meet the applicability criteria at 
the time you commence construction.
    (c) An EGU is reconstructed if you meet the reconstruction criteria 
as defined in Sec.  63.2, you commence reconstruction after May 3, 
2011, and you meet the applicability criteria at the time you commence 
reconstruction.
    (d) An EGU is existing if it is not new or reconstructed. An 
existing electric steam generating unit that meets the applicability 
requirements after the effective date of this final rule due to a 
change process (e.g., fuel or utilization) is considered to be an 
existing source under this subpart.


Sec.  63.9983  Are any EGUs not subject to this subpart?

    The types of electric steam generating units listed in paragraphs 
(a) through (d) of this section are not subject to this subpart.
    (a) Any unit designated as a stationary combustion turbine, other 
than an integrated gasification combined cycle (IGCC) unit, covered by 
40 CFR part 63, subpart YYYY.
    (b) Any electric utility steam generating unit that is not a coal- 
or oil-fired EGU and combusts natural gas for more than 10.0 percent of 
the average annual heat input during any 3 calendar years or for more 
than 15.0 percent of the annual heat input during any calendar year.
    (c) Any electric utility steam generating unit that has the 
capability of combusting more than 25 MW of coal or oil but did not 
fire coal or oil for more than 10.0 percent of the average annual heat 
input during any 3 calendar years or for more than 15.0 percent of the 
annual heat input during any calendar year. Heat input means heat 
derived from combustion of fuel in an EGU and does not include the heat 
derived from preheated combustion air, recirculated flue gases or 
exhaust gases from other sources (such as stationary gas turbines, 
internal combustion engines, and industrial boilers).
    (d) Any electric steam generating unit combusting solid waste is a 
solid waste incineration unit subject to standards established under 
sections 129 and 111 of the Clean Air Act.


Sec.  63.9984  When do I have to comply with this subpart?

    (a) If you have a new or reconstructed EGU, you must comply with 
this subpart by April 16, 2012 or upon startup of your EGU, whichever 
is later, and as further provided for in Sec.  63.10005(g).
    (b) If you have an existing EGU, you must comply with this subpart 
no later than April 16, 2015.
    (c) You must meet the notification requirements in Sec.  63.10030 
according to the schedule in Sec.  63.10030 and in subpart A of this 
part. Some of the notifications must be submitted before you are 
required to comply with the emission limits and work practice standards 
in this subpart.
    (d) An electric steam generating unit that does not meet the 
definition of an EGU subject to this subpart on April 16, 2012 for new 
sources or April 16, 2015 for existing sources must comply with the 
applicable existing source provisions of this subpart on the date such 
unit meets the definition of an EGU subject to this subpart.
    (e) If you own or operate an electric steam generating unit that is 
exempted from this subpart under Sec.  63.9983(d), if the manner of 
operating the unit changes such that the combustion of waste is 
discontinued and the unit becomes a coal-fired or oil-fired EGU (as 
defined in Sec.  63.10042), you must be in compliance with this subpart 
on April 16, 2015 or on the effective date of the switch from waste 
combustion to coal or oil combustion, whichever is later.
    (f) You must demonstrate that compliance has been achieved, by 
conducting the required performance tests and other activities, no 
later than 180 days after the applicable date in paragraph (a), (b), 
(c), (d), or (e) of this section.


Sec.  63.9985  What is a new EGU?

    (a) A new EGU is an EGU that meets any of the criteria specified in 
paragraph (a)(1) through (a)(2) of this section.
    (1) An EGU that commenced construction after May 3, 2011.
    (2) An EGU that commenced reconstruction or modification after May 
3, 2011.
    (b) [Reserved]

Emission Limitations and Work Practice Standards


Sec.  63.9990  What are the subcategories of EGUs?

    (a) Coal-fired EGUs are subcategorized as defined in paragraphs 
(a)(1) through (a)(2) of this section and as defined in Sec.  63.10042.
    (1) EGUs designed for coal with a heating value greater than or 
equal to 8,300 Btu/lb, and
    (2) EGUs designed for low rank virgin coal.
    (b) Oil-fired EGUs are subcategorized as noted in paragraphs (b)(1) 
through (b)(4) of this section and as defined in Sec.  63.10042.
    (1) Continental liquid oil-fired EGUs
    (2) Non-continental liquid oil-fired EGUs,
    (3) Limited-use liquid oil-fired EGUs, and
    (4) EGUs designed to burn solid oil-derived fuel.
    (c) IGCC units combusting either gasified coal or gasified solid 
oil-derived fuel. For purposes of compliance, monitoring, 
recordkeeping, and reporting requirements in this subpart, IGCC units 
are subject in the same manner as coal-fired units and solid oil-
derived fuel-fired units, unless otherwise indicated.


Sec.  63.9991  What emission limitations, work practice standards, and 
operating limits must I meet?

    (a) You must meet the requirements in paragraphs (a)(1) and (2) of 
this section. You must meet these requirements at all times.
    (1) You must meet each emission limit and work practice standard in 
Table 1 through 3 to this subpart that applies to your EGU, for each 
EGU at your source, except as provided under Sec.  63.10009.
    (2) You must meet each operating limit in Table 4 to this subpart 
that applies to your EGU.
    (b) As provided in Sec.  63.6(g), the Administrator may approve use 
of an alternative to the work practice standards in this section.
    (c) You may use the alternate SO2 limit in Tables 1 and 
2 to this subpart only if your coal-fired EGU:
    (1) Has a system using wet or dry flue gas desulfurization 
technology and SO2 continuous emissions monitoring system 
(CEMS) installed on the unit; and
    (2) At all times, you operate the wet or dry flue gas 
desulfurization technology installed on the unit consistent with Sec.  
63.10000(b).

[[Page 9466]]

General Compliance Requirements


Sec.  63.10000  What are my general requirements for complying with 
this subpart?

    (a) You must be in compliance with the emission limits and 
operating limits in this subpart. These limits apply to you at all 
times except during periods of startup and shutdown; however, for coal-
fired, liquid oil-fired, or solid oil-derived fuel-fired EGUs, you are 
required to meet the work practice requirements in Table 3 to this 
subpart during periods of startup or shutdown.
    (b) At all times you must operate and maintain any affected source, 
including associated air pollution control equipment and monitoring 
equipment, in a manner consistent with safety and good air pollution 
control practices for minimizing emissions. Determination of whether 
such operation and maintenance procedures are being used will be based 
on information available to the EPA Administrator which may include, 
but is not limited to, monitoring results, review of operation and 
maintenance procedures, review of operation and maintenance records, 
and inspection of the source.
    (c)(1) For coal-fired units and solid oil-derived fuel-fired units, 
initial performance testing is required for all pollutants, to 
demonstrate compliance with the applicable emission limits.
    (i) For a coal-fired or solid oil-derived fuel-fired EGU or IGCC 
EGU, you may conduct the initial performance testing in accordance with 
Sec.  63.10005(h), to determine whether the unit qualifies as a low 
emitting EGU (LEE) for one or more applicable emissions limits, with 
two exceptions:
    (A) You may not pursue the LEE option if your coal-fired, IGCC, or 
solid oil-derived fuel-fired EGU is equipped with an acid gas scrubber 
and has a main stack and bypass stack exhaust configuration, and
    (B) You may not pursue the LEE option for Hg if your coal-fired, 
solid oil-fired fuel fired EGU or IGCC EGU is new.
    (ii) For a qualifying LEE for Hg emissions limits, you must conduct 
a 30-day performance test using Method 30B at least once every 12 
calendar months to demonstrate continued LEE status.
    (iii) For a qualifying LEE of any other applicable emissions 
limits, you must conduct a performance test at least once every 36 
calendar months to demonstrate continued LEE status.
    (iv) If your coal-fired or solid oil-derived fuel-fired EGU or IGCC 
EGU does not qualify as a LEE for total non-mercury HAP metals, 
individual non-mercury HAP metals, or filterable particulate matter 
(PM), you must demonstrate compliance through an initial performance 
test and you must monitor continuous performance through either use of 
a particulate matter continuous parametric monitoring system (PM CPMS), 
a PM CEMS, or compliance performance testing repeated quarterly.
    (A) If you elect to use PM CPMS, you will establish a site-specific 
operating limit corresponding to the results of the performance test 
demonstrating compliance with the pollutant with which you choose to 
comply: total non-mercury HAP metals, individual non-mercury HAP metals 
or filterable PM. You will use the PM CPMS to demonstrate continuous 
compliance with this operating limit. If you elect to use a PM CPMS, 
you must repeat the performance test annually for the selected 
pollutant limit and reassess and adjust the site-specific operating 
limit in accordance with the results of the performance test.
    (B) You may also opt to install and operate a particulate matter 
CEMS certified in accordance with Performance Specification 11 and 
Procedure 2 of 40 CFR part 60, Appendices B and F, respectively, in 
accordance with Sec.  63.10010(i).
    (v) If your coal-fired or solid oil-derived fuel-fired EGU does not 
qualify as a LEE for hydrogen chloride (HCl), you may demonstrate 
initial and continuous compliance through use of an HCl CEMS, installed 
and operated in accordance with Appendix B to this subpart. As an 
alternative to HCl CEMS, you may demonstrate initial and continuous 
compliance by conducting an initial and periodic quarterly performance 
stack test for HCl. If your EGU uses wet or dry flue gas 
desulfurization technology (this includes limestone injection into a 
fluidized bed combustion unit), you may apply a second alternative to 
HCl CEMS by installing and operating a sulfur dioxide (SO2) 
CEMS installed and operated in accordance with part 75 of this chapter 
to demonstrate compliance with the applicable SO2 emissions 
limit.
    (vi) If your coal-fired or solid oil-derived fuel-fired EGU does 
not qualify as a LEE for Hg, you must demonstrate initial and 
continuous compliance through use of a Hg CEMS or a sorbent trap 
monitoring system, in accordance with appendix A to this subpart.
    (2) For liquid oil-fired EGUs, except limited use liquid oil-fired 
EGUs, initial performance testing is required for all pollutants, to 
demonstrate compliance with the applicable emission limits.
    (i) For an existing liquid oil-fired unit, you may conduct the 
performance testing in accordance with Sec.  63.10005(h), to determine 
whether the unit qualifies as a LEE for one or more pollutants. For a 
qualifying LEE for Hg emissions limits, you must conduct a 30-day 
performance test using Method 30B at least once every 12 calendar 
months to demonstrate continued LEE status. For a qualifying LEE of any 
other applicable emissions limits, you must conduct a performance test 
at least once every 36 calendar months to demonstrate continued LEE 
status.
    (ii) If your existing liquid oil-fired unit does not qualify as a 
LEE for total HAP metals (including mercury), individual metals 
(including mercury), or filterable PM you must demonstrate compliance 
through an initial performance test and you must monitor continuous 
performance through either use of a PM CPMS, a PM CEMS, or performance 
testing conducted quarterly.
    (A) If you elect to use PM CPMS, you will establish a site-specific 
operating limit corresponding to the results of the performance test 
demonstrating compliance with the pollutant with which you choose to 
comply: total HAP metals, individual HAP metals, or filterable PM. You 
will use the PM CPMS to demonstrate continuous compliance with this 
operating limit. If you elect to use a PM CPMS, you must repeat the 
performance test at least annually for the selected pollutant limit and 
reassess and adjust the site-specific operating limit in accordance 
with the results of the performance test.
    (B) If you elect to use a PM CEMS, you will use the CEMS in 
accordance with Sec.  63.10010(i) to demonstrate initial and continuous 
compliance with the filterable PM emission limit.
    (iii) If your existing liquid oil-fired unit does not qualify as a 
LEE for hydrogen chloride (HCl) or for hydrogen fluoride (HF), you may 
demonstrate initial and continuous compliance through use of an HCl 
CEMS, an HF CEMS, or an HCl and HF CEMS, installed and operated in 
accordance with Appendix B to this rule. As an alternative to HCl CEMS, 
HF CEMS, or HCl and HF CEMS, you may demonstrate initial and continuous 
compliance by conducting periodic quarterly performance stack tests for 
HCl and HF. If you elect to demonstrate compliance through quarterly 
performance testing, then you must also develop a site-specific 
monitoring plan to ensure that the operations of the unit remain 
consistent with those during the performance test. As another 
alternative, you may measure or obtain, and keep

[[Page 9467]]

records of, fuel moisture content; as long as fuel moisture does not 
exceed 1.0 percent by weight, you need not conduct other HCl or HF 
monitoring or testing.
    (iv) If your unit qualifies as a limited-use liquid oil-fired as 
defined in Sec.  63.10042, then you are not subject to the emission 
limits in Tables 1 and 2, but must comply with the performance tune-up 
work practice requirements in Table 3.
    (d)(1) If you demonstrate compliance with any applicable emissions 
limit through use of a continuous monitoring system (CMS), where a CMS 
includes a continuous parameter monitoring system (CPMS) as well as a 
continuous emissions monitoring system (CEMS), you must develop a site-
specific monitoring plan and submit this site-specific monitoring plan, 
if requested, at least 60 days before your initial performance 
evaluation (where applicable) of your CMS. This requirement also 
applies to you if you petition the Administrator for alternative 
monitoring parameters under Sec.  63.8(f). This requirement to develop 
and submit a site-specific monitoring plan does not apply to affected 
sources with existing monitoring plans that apply to CEMS and CPMS 
prepared under Appendix B to part 60 or part 75 of this chapter, and 
that meet the requirements of Sec.  63.10010. Using the process 
described in Sec.  63.8(f)(4), you may request approval of monitoring 
system quality assurance and quality control procedures alternative to 
those specified in this paragraph of this section and, if approved, 
include those in your site-specific monitoring plan. The monitoring 
plan must address the provisions in paragraphs (d)(2) through (5) of 
this section.
    (2) The site-specific monitoring plan shall include the information 
specified in paragraphs (d)(5)(i) through (d)(5)(vii) of this section. 
Alternatively, the requirements of paragraphs (d)(5)(i) through 
(d)(5)(vii) are considered to be met for a particular CMS or sorbent 
trap monitoring system if:
    (i) The CMS or sorbent trap monitoring system is installed, 
certified, maintained, operated, and quality-assured either according 
to part 75 of this chapter, or appendix A or B to this subpart; and
    (ii) The recordkeeping and reporting requirements of part 75 of 
this chapter, or appendix A or B to this subpart, that pertain to the 
CMS are met.
    (3) If requested by the Administrator, you must submit the 
monitoring plan (or relevant portion of the plan) at least 60 days 
before the initial performance evaluation of a particular CMS, except 
where the CMS has already undergone a performance evaluation that meets 
the requirements of Sec.  63.10010 (e.g., if the CMS was previously 
certified under another program).
    (4) You must operate and maintain the CMS according to the site-
specific monitoring plan.
    (5) The provisions of the site-specific monitoring plan must 
address the following items:
    (i) Installation of the CEMS or sorbent trap monitoring system 
sampling probe or other interface at a measurement location relative to 
each affected process unit such that the measurement is representative 
of control of the exhaust emissions (e.g., on or downstream of the last 
control device). See Sec.  63.10010(a) for further details. For CPMS 
installations, follow the procedures in Sec.  63.10010(h).
    (ii) Performance and equipment specifications for the sample 
interface, the pollutant concentration or parametric signal analyzer, 
and the data collection and reduction systems.
    (iii) Schedule for conducting initial and periodic performance 
evaluations.
    (iv) Performance evaluation procedures and acceptance criteria 
(e.g., calibrations), including ongoing data quality assurance 
procedures in accordance with the general requirements of Sec.  
63.8(d).
    (v) On-going operation and maintenance procedures, in accordance 
with the general requirements of Sec. Sec.  63.8(c)(1)(ii), (c)(3), and 
(c)(4)(ii).
    (vi) Conditions that define a CMS that is out of control consistent 
with Sec.  63.8(c)(7)(i) and for responding to out of control periods 
consistent with Sec. Sec.  63.8(c)(7)(ii) and (c)(8).
    (vii) On-going recordkeeping and reporting procedures, in 
accordance with the general requirements of Sec. Sec.  63.10(c), 
(e)(1), and (e)(2)(i), or as specifically required under this subpart.
    (e) As part of your demonstration of continuous compliance, you 
must perform periodic tune-ups of your EGU(s), according to Sec.  
63.10021(e).
    (f) You are subject to the requirements of this subpart for at 
least 6 months following the last date you met the definition of an EGU 
subject to this subpart (e.g., 6 months after a cogeneration unit 
provided more than one third of its potential electrical output 
capacity and more than 25 megawatts electrical output to any power 
distributions system for sale). You may opt to remain subject to the 
provisions of this subpart beyond 6 months after the last date you met 
the definition of an EGU subject to this subpart, unless you are a 
solid waste incineration unit subject to standards under CAA section 
129 (e.g., 40 CFR part 60, subpart CCCC (New Source Performance 
Standards (NSPS) for Commercial and Industrial Solid Waste Incineration 
Units, or Subpart DDDD (Emissions Guidelines (EG) for Existing 
Commercial and Industrial Solid Waste Incineration Units). 
Notwithstanding the provisions of this subpart, an EGU that starts 
combusting solid waste is immediately subject to standards under CAA 
section 129 and the EGU remains subject to those standards until the 
EGU no longer meets the definition of a solid waste incineration unit 
consistent with the provisions of the applicable CAA section 129 
standards.
    (g) If you no longer meet the definition of an EGU subject to this 
subpart you must be in compliance with any newly applicable standards 
on the date you are no longer subject to this subpart. The date you are 
no longer subject to this subpart is a date selected by you, that must 
be at least 6 months from the date that you last met the definition of 
an EGU subject to this subpart or the date you begin combusting solid 
waste, consistent with Sec.  63.9983(d). Your source must remain in 
compliance with this subpart until the date you select to cease 
complying with this subpart or the date you begin combusting solid 
waste, whichever is earlier.
    (h)(1) If you own or operate an EGU that does not meet the 
definition of an EGU subject to this subpart on April 16, 2015, and you 
commence or recommence operations that cause you to meet the definition 
of an EGU subject to this subpart, you are subject to the provisions of 
this subpart, including, but not limited to, the emission limitations 
and the monitoring requirements, as of the first day you meet the 
definition of an EGU subject to this subpart. You must complete all 
initial compliance demonstrations for this subpart applicable to your 
EGU within 180 days after you commence or recommence operations that 
cause you to meet the definition of an EGU subject to this subpart.
    (2) You must provide 30 days prior notice of the date you intend to 
commence or recommence operations that cause you to meet the definition 
of an EGU subject to this subpart. The notification must identify:
    (i) The name of the owner or operator of the EGU, the location of 
the facility, the unit(s) that will commence or recommence operations 
that will cause the unit(s) to meet the definition of an EGU subject to 
this subpart, and the date of the notice;
    (ii) The 40 CFR part 60, part 62, or part 63 subpart and 
subcategory

[[Page 9468]]

currently applicable to your unit(s), and the subcategory of this 
subpart that will be applicable after you commence or recommence 
operation that will cause the unit(s) to meet the definition of an EGU 
subject to this subpart;
    (iii) The date on which you became subject to the currently 
applicable emission limits;
    (iv) The date upon which you will commence or recommence operations 
that will cause your unit to meet the definition of an EGU subject to 
this subpart, consistent with paragraph (f) of this section.
    (i)(1) If you own or operate an EGU subject to this subpart, and it 
has been at least 6 months since you operated in a manner that caused 
you to meet the definition of an EGU subject to this subpart, you may, 
consistent with paragraph (g) of this section, select the date on which 
your EGU will no longer be subject to this subpart. You must be in 
compliance with any newly applicable section 112 or 129 standards on 
the date you selected.
    (2) You must provide 30 days prior notice of the date your EGU will 
cease complying with this subpart. The notification must identify:
    (i) The name of the owner or operator of the EGU(s), the location 
of the facility, the EGU(s) that will cease complying with this 
subpart, and the date of the notice;
    (ii) The currently applicable subcategory under this subpart, and 
any 40 CFR part 60, part 62, or part 63 subpart and subcategory that 
will be applicable after you cease complying with this subpart;
    (iii) The date on which you became subject to this subpart;
    (iv) The date upon which you will cease complying with this 
subpart, consistent with paragraph (g) of this section.
    (j) All air pollution control equipment necessary for compliance 
with any newly applicable emissions limits which apply as a result of 
the cessation or commencement or recommencement of operations that 
cause your EGU to meet the definition of an EGU subject to this subpart 
must be installed and operational as of the date your source ceases to 
be or becomes subject to this subpart.
    (k) All monitoring systems necessary for compliance with any newly 
applicable monitoring requirements which apply as a result of the 
cessation or commencement or recommencement of operations that cause 
your EGU to meet the definition of an EGU subject to this subpart must 
be installed and operational as of the date your source ceases to be or 
becomes subject to this subpart. All calibration and drift checks must 
be performed as of the date your source ceases to be or becomes subject 
to this subpart. You must also comply with provisions of Sec. Sec.  
63.10010, 63.10020, and 63.10021 of this subpart. Relative accuracy 
tests must be performed as of the performance test deadline for PM 
CEMS, if applicable. Relative accuracy testing for other CEMS need not 
be repeated if that testing was previously performed consistent with 
CAA section 112 monitoring requirements or monitoring requirements 
under this subpart.


Sec.  63.10001  Affirmative defense for exceedence of emission limit 
during malfunction.

    In response to an action to enforce the standards set forth in 
Sec.  63.9991 you may assert an affirmative defense to a claim for 
civil penalties for exceedances of such standards that are caused by 
malfunction, as defined at 40 CFR 63.2. Appropriate penalties may be 
assessed, however, if you fail to meet your burden of proving all of 
the requirements in the affirmative defense. The affirmative defense 
shall not be available for claims for injunctive relief.
    (a) To establish the affirmative defense in any action to enforce 
such a limit, you must timely meet the notification requirements in 
paragraph (b) of this section, and must prove by a preponderance of 
evidence that:
    (1) The excess emissions:
    (i) Were caused by a sudden, infrequent, and unavoidable failure of 
air pollution control and monitoring equipment, process equipment, or a 
process to operate in a normal or usual manner, and
    (ii) Could not have been prevented through careful planning, proper 
design or better operation and maintenance practices; and
    (iii) Did not stem from any activity or event that could have been 
foreseen and avoided, or planned for; and
    (iv) Were not part of a recurring pattern indicative of inadequate 
design, operation, or maintenance; and
    (2) Repairs were made as expeditiously as possible when the 
applicable emission limitations were being exceeded. Off-shift and 
overtime labor were used, to the extent practicable to make these 
repairs; and
    (3) The frequency, amount and duration of the excess emissions 
(including any bypass) were minimized to the maximum extent practicable 
during periods of such emissions; and
    (4) If the excess emissions resulted from a bypass of control 
equipment or a process, then the bypass was unavoidable to prevent loss 
of life, personal injury, or severe property damage; and
    (5) All possible steps were taken to minimize the impact of the 
excess emissions on ambient air quality, the environment and human 
health; and
    (6) All emissions monitoring and control systems were kept in 
operation if at all possible, consistent with safety and good air 
pollution control practices; and
    (7) All of the actions in response to the excess emissions were 
documented by properly signed, contemporaneous operating logs; and
    (8) At all times, the affected source was operated in a manner 
consistent with good practices for minimizing emissions; and
    (9) A written root cause analysis has been prepared, the purpose of 
which is to determine, correct, and eliminate the primary causes of the 
malfunction and the excess emissions resulting from the malfunction 
event at issue. The analysis shall also specify, using best monitoring 
methods and engineering judgment, the amount of excess emissions that 
were the result of the malfunction.
    (b) Notification. The owner or operator of the affected source 
experiencing an exceedance of its emission limit(s) during a 
malfunction shall notify the Administrator by telephone or facsimile 
(FAX) transmission as soon as possible, but no later than two business 
days after the initial occurrence of the malfunction or, if it is not 
possible to determine within two business days whether the malfunction 
caused or contributed to an exceedance, no later than two business days 
after the owner or operator knew or should have known that the 
malfunction caused or contributed to an exceedance, but, in no event 
later than two business days after the end of the averaging period, if 
it wishes to avail itself of an affirmative defense to civil penalties 
for that malfunction. The owner or operator seeking to assert an 
affirmative defense shall also submit a written report to the 
Administrator within 45 days of the initial occurrence of the 
exceedance of the standard in Sec.  63.9991 to demonstrate, with all 
necessary supporting documentation, that it has met the requirements 
set forth in paragraph (a) of this section. The owner or operator may 
seek an extension of this deadline for up to 30 additional days by 
submitting a written request to the Administrator before the expiration 
of the 45 day period. Until a request for an extension has been 
approved by the Administrator, the owner or operator is subject to the 
requirement to submit such report

[[Page 9469]]

within 45 days of the initial occurrence of the exceedance.

Testing and Initial Compliance Requirements


Sec.  63.10005  What are my initial compliance requirements and by what 
date must I conduct them?

    (a) General requirements. For each of your affected EGUs, you must 
demonstrate initial compliance with each applicable emissions limit in 
Table 1 or 2 of this subpart through performance testing. Where two 
emissions limits are specified for a particular pollutant (e.g., a heat 
input-based limit in lb/MMBtu and an electrical output-based limit in 
lb/MWh), you may demonstrate compliance with either emission limit. For 
a particular compliance demonstration, you may be required to conduct 
one or more of the following activities in conjunction with performance 
testing: collection of hourly electrical load data (megawatts); 
establishment of operating limits according to Sec.  63.10011 and 
Tables 4 and 7 to this subpart; and CMS performance evaluations. In all 
cases, you must demonstrate initial compliance no later than the 
applicable date in paragraph (f) of this section for tune-up work 
practices for existing EGUs, in Sec.  63.9984 for other requirements 
for existing EGUs, and in paragraph (g) of this section for all 
requirements for new EGUs.
    (1) To demonstrate initial compliance with an applicable emissions 
limit in Table 1 or 2 to this subpart using stack testing, the initial 
performance test generally consists of three runs at specified process 
operating conditions using approved methods. If you are required to 
establish operating limits (see paragraph (d) of this section and Table 
4 to this subpart), you must collect all applicable parametric data 
during the performance test period. Also, if you choose to comply with 
an electrical output-based emission limit, you must collect hourly 
electrical load data during the test period.
    (2) To demonstrate initial compliance using either a CMS that 
measures HAP concentrations directly (i.e., an Hg, HCl, or HF CEMS, or 
a sorbent trap monitoring system) or an SO2 or PM CEMS, the 
initial performance test consists of 30 boiler operating days of data 
collected by the initial compliance demonstration date specified in 
Sec.  63.10005 with the certified monitoring system.
    (i) The 30-boiler operating day CMS performance test must 
demonstrate compliance with the applicable Hg, HCl, HF, PM, or 
SO2 emissions limit in Table 1 or 2 to this subpart.
    (ii) If you choose to comply with an electrical output-based 
emission limit, you must collect hourly electrical load data during the 
performance test period.
    (b) Performance testing requirements. If you choose to use 
performance testing to demonstrate initial compliance with the 
applicable emissions limits in Tables 1 and 2 to this subpart for your 
EGUs, you must conduct the tests according to Sec.  63.10007 and Table 
5 to this subpart. For the purposes of the initial compliance 
demonstration, you may use test data and results from a performance 
test conducted prior to the date on which compliance is required as 
specified in Sec.  63.9984, provided that the following conditions are 
fully met:
    (1) For a performance test based on stack test data, the test was 
conducted no more than 12 calendar months prior to the date on which 
compliance is required as specified in Sec.  63.9984;
    (2) For a performance test based on data from a certified CEMS or 
sorbent trap monitoring system, the test consists of all valid data CMS 
data recorded in the 30 boiler operating days immediately preceding 
that date;
    (3) The performance test was conducted in accordance with all 
applicable requirements in Sec.  63.10007 and Table 5 to this subpart;
    (4) A record of all parameters needed to convert pollutant 
concentrations to units of the emission standard (e.g., stack flow 
rate, diluent gas concentrations, hourly electrical loads) is available 
for the entire performance test period; and
    (5) For each performance test based on stack test data, you 
certify, and keep documentation demonstrating, that the EGU 
configuration, control devices, and fuel(s) have remained consistent 
with conditions since the prior performance test was conducted.
    (c) Operating limits. In accordance with Sec.  63.10010 and Table 4 
to this subpart, you may be required to establish operating limits 
using PM CPMS and using site-specific monitoring for certain liquid 
oil-fired units as part of your initial compliance demonstration.
    (d) CMS requirements. If, for a particular emission or operating 
limit, you are required to (or elect to) demonstrate initial compliance 
using a continuous monitoring system, the CMS must pass a performance 
evaluation prior to the initial compliance demonstration. If a CMS has 
been previously certified under another state or federal program and is 
continuing to meet the on-going quality-assurance (QA) requirements of 
that program, then, provided that the certification and QA provisions 
of that program meet the applicable requirements of Sec. Sec.  
63.10010(b) through (h), an additional performance evaluation of the 
CMS is not required under this subpart.
    (1) For an affected coal-fired, solid oil-derived fuel-fired, or 
liquid oil-fired EGU, you may demonstrate initial compliance with the 
applicable SO2, HCl, or HF emissions limit in Table 1 or 2 
of this subpart through use of an SO2, HCl, or HF CEMS 
installed and operated in accordance with part 75 of this chapter or 
Appendix B to this subpart, as applicable. You may also demonstrate 
compliance with a filterable PM emission limit in Table 1 or 2 of this 
subpart through use of a PM CEMS installed, certified, and operated in 
accordance with Sec.  63.10010(i). Initial compliance is achieved if 
the arithmetic average of 30-boiler operating days of quality-assured 
CEMS data, expressed in units of the standard (see Sec.  63.10007(e)), 
meets the applicable SO2, PM, HCl, or HF emissions limit in 
Table 1 or 2 to this subpart. Use Equation 19-19 of Method 19 in 
appendix A-7 to part 60 of this chapter to calculate the 30-boiler 
operating day average emissions rate. (Note: for this calculation, the 
term Ehj in Equation 19-19 must be in the same units of 
measure as the applicable HCl or HF emission limit in Table 1 or 2 to 
this subpart).
    (2) For affected coal-fired or solid oil-derived fuel-fired EGUs 
that demonstrate compliance with the applicable emission limits for 
total non-mercury HAP metals, individual non-mercury HAP metals, total 
HAP metals, individual HAP metals, or filterable PM listed in Table 1 
or 2 to this subpart using initial performance testing and continuous 
monitoring with PM CPMS:
    (i) You must demonstrate initial compliance no later than the 
applicable date specified in Sec.  63.9984(f) for existing EGUs and in 
paragraph (g) of this section for new EGUs.
    (ii) You must demonstrate continuous compliance with the PM CPMS 
site-specific operating limit that corresponding to the results of the 
performance test demonstrating compliance with the pollutant with which 
you choose to comply.
    (iii) You must repeat the performance test annually for the 
selected pollutant emissions limit and reassess and adjust the site-
specific operating limit in accordance with the results of the 
performance test.
    (3) For affected EGUs that are either required to or elect to 
demonstrate initial compliance with the applicable Hg emission limit in 
Table 1 or 2 of this

[[Page 9470]]

subpart using Hg CEMS or sorbent trap monitoring systems, initial 
compliance must be demonstrated no later than the applicable date 
specified in Sec.  63.9984(f) for existing EGUs and in paragraph (g) of 
this section for new EGUs. Initial compliance is achieved if the 
arithmetic average of 30-boiler operating days of quality-assured CEMS 
(or sorbent trap monitoring system) data, expressed in units of the 
standard (see section 6.2 of appendix A to this subpart), meets the 
applicable Hg emission limit in Table 1 or 2 to this subpart.
    (4) For affected liquid oil-fired EGUs that demonstrate compliance 
with the applicable emission limits for HCl or HF listed in Table 1 or 
2 to this subpart using quarterly testing and continuous monitoring 
with a CMS:
    (i) You must demonstrate initial compliance no later than the 
applicable date specified in Sec.  63.9984 for existing EGUs and in 
paragraph (g) of this section for new EGUs.
    (ii) You must demonstrate continuous compliance with the CMS site-
specific operating limit that corresponding to the results of the 
performance test demonstrating compliance with the HCl or HF emissions 
limit.
    (iii) You must repeat the performance test annually for the HCl or 
HF emissions limit and reassess and adjust the site-specific operating 
limit in accordance with the results of the performance test.
    (e) Tune-ups. All affected EGUs are subject to the work practice 
standards in Table 3 of this subpart. As part of your initial 
compliance demonstration, you must conduct a performance tune-up of 
your EGU according to Sec.  63.10021(e).
    (f) For existing affected sources a tune-up may occur prior to 
April 16, 2012, so that existing sources without neural networks have 
up to 42 calendar months (3 years from promulgation plus 180 days) or, 
in the case of units employing neural network combustion controls, up 
to 54 calendar months (48 months from promulgation plus 180 days) after 
the date that is specified for your source in Sec.  63.9984 and 
according to the applicable provisions in Sec.  63.7(a)(2) as cited in 
Table 9 to this subpart to demonstrate compliance with this 
requirement. If a tune-up occurs prior to such date, the source must 
maintain adequate records to show that the tune-up met the requirements 
of this standard.
    (g) If your new or reconstructed affected source commenced 
construction or reconstruction between May 3, 2011, and July 2, 2011, 
you must demonstrate initial compliance with either the proposed 
emission limits or the promulgated emission limits no later than 180 
days after April 16, 2012 or within 180 days after startup of the 
source, whichever is later, according to Sec.  63.7(a)(2)(ix).
    (1) For the new or reconstructed affected source described in this 
paragraph (g), if you choose to comply with the proposed emission 
limits when demonstrating initial compliance, you must conduct a second 
compliance demonstration for the promulgated emission limits within 3 
years after April 16, 2012 or within 3 years after startup of the 
affected source, whichever is later.
    (2) If your new or reconstructed affected source commences 
construction or reconstruction after April 16, 2012, you must 
demonstrate initial compliance with the promulgated emission limits no 
later than 180 days after startup of the source.
    (h) Low emitting EGUs. The provisions of this paragraph (h) apply 
to pollutants with emissions limits from new EGUs except Hg and to all 
pollutants with emissions limits from existing EGUs. You may not pursue 
this compliance option if your existing EGU is equipped with an acid 
gas scrubber and has a main stack and bypass stack exhaust 
configuration.
    (1) An EGU may qualify for low emitting EGU (LEE) status for Hg, 
HCl, HF, filterable PM, total non-Hg HAP metals, or individual non-Hg 
HAP metals (or total HAP metals or individual HAP metals, for liquid 
oil-fired EGUs) if you collect performance test data that meet the 
requirements of this paragraph (h), and if those data demonstrate:
    (i) For all pollutants except Hg, performance test emissions 
results less than 50 percent of the applicable emissions limits in 
Table 1 or 2 to this subpart for all required testing for 3 consecutive 
years; or
    (ii) For Hg emissions from an existing EGU, either:
    (A) Average emissions less than 10 percent of the applicable Hg 
emissions limit in Table 2 to this subpart (expressed either in units 
of lb/TBtu or lb/GWh); or
    (B) Potential Hg mass emissions of 29.0 or fewer pounds per year 
and compliance with the applicable Hg emission limit in Table 2 to this 
subpart (expressed either in units of lb/TBtu or lb/GWh).
    (2) For all pollutants except Hg, you must conduct all required 
performance tests described in Sec.  63.10007 to demonstrate that a 
unit qualifies for LEE status.
    (i) When conducting emissions testing to demonstrate LEE status, 
you must increase the minimum sample volume specified in Table 1 or 2 
nominally by a factor of two.
    (ii) Follow the instructions in Sec.  63.10007(e) and Table 5 to 
this subpart to convert the test data to the units of the applicable 
standard.
    (3) For Hg, you must conduct a 30-boiler operating day performance 
test using Method 30B in appendix A-8 to part 60 of this chapter to 
determine whether a unit qualifies for LEE status. Locate the Method 
30B sampling probe tip at a point within the 10 percent centroidal area 
of the duct at a location that meets Method 1 in appendix A-1 to part 
60 of this chapter and conduct at least three nominally equal length 
test runs over the 30-boiler operating day test period. Collect Hg 
emissions data continuously over the entire test period (except when 
changing sorbent traps or performing required reference method QA 
procedures), under all process operating conditions. You may use a pair 
of sorbent traps to sample the stack gas for no more than 10 days.
    (i) Depending on whether you intend to assess LEE status for Hg in 
terms of the lb/TBtu or lb/GWh emission limit in Table 2 to this 
subpart or in terms of the annual Hg mass emissions limit of 29.0 lb/
year, you will have to collect some or all of the following data during 
the 30-boiler operating day test period (see paragraph (h)(3)(iii) of 
this section):
    (A) Diluent gas (CO2 or O2) data, using 
either Method 3A in appendix A-3 to part 60 of this chapter or a 
diluent gas monitor that has been certified according to part 75 of 
this chapter.
    (B) Stack gas flow rate data, using either Method 2, 2F, or 2G in 
appendices A-1 and A-2 to part 60 of this chapter, or a flow rate 
monitor that has been certified according to part 75 of this chapter.
    (C) Stack gas moisture content data, using either Method 4 in 
appendix A-1 to part 60 of this chapter, or a moisture monitoring 
system that has been certified according to part 75 of this chapter. 
Alternatively, an appropriate fuel-specific default moisture value from 
Sec.  75.11(b) of this chapter may be used in the calculations or you 
may petition the Administrator under Sec.  75.66 of this chapter for 
use of a default moisture value for non-coal-fired units.
    (D) Hourly electrical load data (megawatts), from facility records.
    (ii) If you use CEMS to measure CO2 (or O2) 
concentration, and/or flow rate, and/or moisture, record hourly average 
values of each parameter throughout the 30-boiler operating day test 
period. If you opt to use EPA reference methods rather than CEMS for 
any parameter, you must perform at least one

[[Page 9471]]

representative test run on each operating day of the test period, using 
the applicable reference method.
    (iii) Calculate the average Hg concentration, in [micro]g/
m3 (dry basis), for the 30-boiler operating day performance 
test, as the arithmetic average of all Method 30B sorbent trap results. 
Also calculate, as applicable, the average values of CO2 or 
O2 concentration, stack gas flow rate, stack gas moisture 
content, and electrical load for the test period. Then:
    (A) To express the test results in units of lb/TBtu, follow the 
procedures in Sec.  63.10007(e). Use the average Hg concentration and 
diluent gas values in the calculations.
    (B) To express the test results in units of lb/GWh, use Equations 
A-3 and A-4 in section 6.2.2 of appendix A to this subpart, replacing 
the hourly values ``Ch'', ``Qh'', 
``Bws'' and ``(MW)h'' with the average values of 
these parameters from the performance test.
    (C) To calculate pounds of Hg per year, use one of the following 
methods:
    (1) Multiply the average lb/TBtu Hg emission rate (determined 
according to paragraph (h)(3)(iii)(A) of this section) by the maximum 
potential annual heat input to the unit (TBtu), which is equal to the 
maximum rated unit heat input (TBtu/hr) times 8,760 hours. If the 
maximum rated heat input value is expressed in units of MMBtu/hr, 
multiply it by 106 to convert it to TBtu/hr; or
    (2) Multiply the average lb/GWh Hg emission rate (determined 
according to paragraph (h)(3)(iii)(B) of this section) by the maximum 
potential annual electricity generation (GWh), which is equal to the 
maximum rated electrical output of the unit (GW) times 8,760 hours. If 
the maximum rated electrical output value is expressed in units of MW, 
multiply it by 103 to convert it to GW; or
    (3) If an EGU has a federally-enforceable permit limit on either 
the annual heat input or the number of annual operating hours, you may 
modify the calculations in paragraph (h)(3)(iii)(C)(1) of this section 
by replacing the maximum potential annual heat input or 8,760 unit 
operating hours with the permit limit on annual heat input or operating 
hours (as applicable).
    (4) For a group of affected units that vent to a common stack, you 
may either assess LEE status for the units individually by performing a 
separate emission test of each unit in the duct leading from the unit 
to the common stack, or you may perform a single emission test in the 
common stack. If you choose the common stack testing option, the units 
in the configuration qualify for LEE status if:
    (i) The emission rate measured at the common stack is less than 50 
percent (10 percent for Hg) of the applicable emission limit in Table 1 
or 2 to this subpart; or
    (ii) For Hg from an existing EGU, the applicable Hg emission limit 
in Table 2 to this subpart is met and the potential annual mass 
emissions, calculated according to paragraph (h)(3)(iii) of this 
section (with some modifications), are less than or equal to 29.0 
pounds times the number of units sharing the common stack. Base your 
calculations on the combined heat input capacity of all units sharing 
the stack (i.e., either the combined maximum rated value or, if 
applicable, a lower combined value restricted by permit conditions or 
operating hours).
    (5) For an affected unit with a multiple stack or duct 
configuration in which the exhaust stacks or ducts are downstream of 
all emission control devices, you must perform a separate emission test 
in each stack or duct. The unit qualifies for LEE status if:
    (i) The emission rate, based on all test runs performed at all of 
the stacks or ducts, is less than 50 percent (10 percent for Hg) of the 
applicable emission limit in Table 1 or 2 to this subpart; or
    (ii) For Hg from an existing EGU, the applicable Hg emission limit 
in Table 2 to this subpart is met and the potential annual mass 
emissions, calculated according to paragraph (h)(3)(iii) of this 
section, are less than or equal to 29.0 pounds. Use the average Hg 
emission rate from paragraph (h)(5)(i) of this section in your 
calculations.
    (i) Liquid-oil fuel moisture measurement. If your EGU combusts 
liquid fuels, if your fuel moisture content is no greater than 1.0 
percent by weight, and if you would like to demonstrate initial and 
ongoing compliance with HCl and HF emissions limits, you must meet the 
requirements of paragraphs (i)(1) through (5) of this section.
    (1) Measure fuel moisture content of each shipment of fuel if your 
fuel arrives on a batch basis; or
    (2) Measure fuel moisture content daily if your fuel arrives on a 
continuous basis; or
    (3) Obtain and maintain a fuel moisture certification from your 
fuel supplier.
    (4) Use one of the following methods to determine fuel moisture 
content:
    (i) ASTM D95-05 (Reapproved 2010), ``Standard Test Method for Water 
in Petroleum Products and Bituminous Materials by Distillation,'' or
    (ii) ASTM D4006-11, ``Standard Test Method for Water in Crude Oil 
by Distillation,'' including Annex A1 and Appendix A1, or
    (iii) ASTM D4177-95 (Reapproved 2010), ``Standard Practice for 
Automatic Sampling of Petroleum and Petroleum Products,'' including 
Annexes A1 through A6 and Appendices X1 and X2, or
    (iv) ASTM D4057-06 (Reapproved 2011), ``Standard Practice for 
Manual Sampling of Petroleum and Petroleum Products,'' including Annex 
A1.
    (5) Should the moisture in your liquid fuel be more than 1.0 
percent by weight, you must
    (i) Conduct HCl and HF emissions testing quarterly (and monitor 
site-specific operating parameters as provided in Sec.  
63.10000(c)(2)(iii) or
    (ii) Use an HCl CEMS and/or HF CEMS.
    (j) Startup and shutdown for coal-fired or solid oil derived-fired 
units. You must follow the requirements given in Table 3 to this 
subpart.
    (k) You must submit a Notification of Compliance Status summarizing 
the results of your initial compliance demonstration, as provided in 
Sec.  63.10030.


Sec.  63.10006  When must I conduct subsequent performance tests or 
tune-ups?

    (a) For liquid oil-fired, solid oil-derived fuel- and coal-fired 
EGUs and IGCC units using PM CPMS to monitor continuous performance 
with an applicable emission limit as provided for under Sec.  
63.10000(c), you must conduct all applicable performance tests 
according to Table 5 to this subpart and Sec.  63.10007 at least every 
year.
    (b) For affected units meeting the LEE requirements of Sec.  
63.10005(h), you must repeat the performance test once every 3 years 
(once every year for Hg) according to Table 5 and Sec.  63.10007. 
Should subsequent emissions testing results show the unit does not meet 
the LEE eligibility requirements, LEE status is lost. If this should 
occur:
    (1) For all pollutant emission limits except for Hg, you must 
conduct emissions testing quarterly, except as otherwise provided in 
Sec.  63.10021(d)(1).
    (2) For Hg, you must install, certify, maintain, and operate a Hg 
CEMS or a sorbent trap monitoring system in accordance with appendix A 
to this subpart, within 6 calendar months of losing LEE eligibility. 
Until the Hg CEMS or sorbent trap monitoring system is installed, 
certified, and operating, you must conduct Hg emissions testing 
quarterly, except as otherwise provided in Sec.  63.10021(d)(1). You 
must have 3 calendar years of testing and CEMS or

[[Page 9472]]

sorbent trap monitoring system data that satisfy the LEE emissions 
criteria to reestablish LEE status.
    (c) Except where paragraphs (a) or (b) of this section apply, or 
where you install, certify, and operate a PM CEMS to demonstrate 
compliance with a filterable PM emission limit, for liquid oil-fired 
EGUs, you must conduct all applicable periodic emissions tests for 
filterable PM, or individual or total HAP metals emissions according to 
Table 5 to this subpart and Sec.  63.10007 at least quarterly, except 
as otherwise provided in Sec.  63.10021(d)(1).
    (d) Except where paragraph (b) of this section applies, for solid 
oil-derived fuel- and coal-fired EGUs that do not use either an HCl 
CEMS to monitor compliance with the HCl limit or an SO2 CEMS 
to monitor compliance with the alternate equivalent SO2 
emission limit, you must conduct all applicable periodic HCl emissions 
tests according to Table 5 to this subpart and Sec.  63.10007 at least 
quarterly, except as otherwise provided in Sec.  63.10021(d)(1).
    (e) Except where paragraph (b) of this section applies, for liquid 
oil-fired EGUs without HCl CEMS, HF CEMS, or HCl and HF CEMS, you must 
conduct all applicable emissions tests for HCl, HF, or HCl and HF 
emissions according to Table 5 to this subpart and Sec.  63.10007 at 
least quarterly, except as otherwise provided in Sec.  63.10021(d)(1), 
and conduct site-specific monitoring under a plan as provided for in 
Sec.  63.10000(c)(2)(iii).
    (f) Unless you follow the requirements listed in paragraphs (g) and 
(h) of this section, performance tests required at least every 3 
calendar years must be completed within 35 to 37 calendar months after 
the previous performance test; performance tests required at least 
every year must be completed within 11 to 13 calendar months after the 
previous performance test; and performance tests required at least 
quarterly must be completed within 80 to 100 calendar days after the 
previous performance test, except as otherwise provided in Sec.  
63.10021(d)(1).
    (g) If you elect to demonstrate compliance using emissions 
averaging under Sec.  63.10009, you must continue to conduct 
performance stack tests at the appropriate frequency given in section 
(c) through (f) of this section.
    (h) If a performance test on a non-mercury LEE shows emissions in 
excess of 50 percent of the emission limit and if you choose to reapply 
for LEE status, you must conduct performance tests at the appropriate 
frequency given in section (c) through (e) of this section for that 
pollutant until all performance tests over a consecutive 3-year period 
show compliance with the LEE criteria.
    (i) If you are required to meet an applicable tune-up work practice 
standard, you must conduct a performance tune-up according to Sec.  
63.10021(e).
    (1) For EGUs not employing neural network combustion optimization 
during normal operation, each performance tune-up specified in Sec.  
63.10021(e) must be no more than 36 calendar months after the previous 
performance tune-up.
    (2) For EGUs employing neural network combustion optimization 
systems during normal operation, each performance tune-up specified in 
Sec.  63.10021(e) must be no more than 48 calendar months after the 
previous performance tune-up.
    (j) You must report the results of performance tests and 
performance tune-ups within 60 days after the completion of the 
performance tests and performance tune-ups. The reports for all 
subsequent performance tests must include all applicable information 
required in Sec.  63.10031.


Sec.  63.10007  What methods and other procedures must I use for the 
performance tests?

    (a) Except as otherwise provided in this section, you must conduct 
all required performance tests according to Sec.  63.7(d), (e), (f), 
and (h). You must also develop a site-specific test plan according to 
the requirements in Sec.  63.7(c).
    (1) If you use CEMS (Hg, HCl, SO2, or other) to 
determine compliance with a 30-boiler operating day rolling average 
emission limit, you must collect data for all nonexempt unit operating 
conditions (see Sec.  63.10011(g) and Table 3 to this subpart).
    (2) If you conduct performance testing with test methods in lieu of 
continuous monitoring, operate the unit at maximum normal operating 
load conditions during each periodic (e.g., quarterly) performance 
test. Maximum normal operating load will be generally between 90 and 
110 percent of design capacity but should be representative of site 
specific normal operations during each test run.
    (3) For establishing operating limits with particulate matter 
continuous parametric monitoring system (PM CPMS) to demonstrate 
compliance with a PM or non Hg metals emissions limit, operate the unit 
at maximum normal operating load conditions during the performance test 
period. Maximum normal operating load will be generally between 90 and 
110 percent of design capacity but should be representative of site 
specific normal operations during each test run.
    (b) You must conduct each performance test (including traditional 
3-run stack tests, 30-boiler operating day tests based on CEMS data (or 
sorbent trap monitoring system data), and 30-boiler operating day Hg 
emission tests for LEE qualification) according to the requirements in 
Table 5 to this subpart.
    (c) If you choose to comply with the filterable PM emission limit 
and demonstrate continuous performance using a PM CPMS for an 
applicable emission limit as provided for in Sec.  63.10000(c), you 
must also establish an operating limit according to Sec.  
63.10011(b)(5) and Tables 4 and 6 to this subpart. Should you desire to 
have operating limits that correspond to loads other than maximum 
normal operating load, you must conduct testing at those other loads to 
determine the additional operating limits.
    (d) Except for a 30-boiler operating day performance test based on 
CEMS (or sorbent trap monitoring system) data, where the concept of 
test runs does not apply, you must conduct a minimum of three separate 
test runs for each performance test, as specified in Sec.  63.7(e)(3). 
Each test run must comply with the minimum applicable sampling time or 
volume specified in Table 1 or 2 to this subpart. Sections 63.10005(d) 
and (h), respectively, provide special instructions for conducting 
performance tests based on CEMS or sorbent trap monitoring systems, and 
for conducting emission tests for LEE qualification.
    (e) To use the results of performance testing to determine 
compliance with the applicable emission limits in Table 1 or 2 to this 
subpart, proceed as follows:
    (1) Except for a 30-boiler operating day performance test based on 
CEMS (or sorbent trap monitoring system) data, if measurement results 
for any pollutant are reported as below the method detection level 
(e.g., laboratory analytical results for one or more sample components 
are below the method defined analytical detection level), you must use 
the method detection level as the measured emissions level for that 
pollutant in calculating compliance. The measured result for a multiple 
component analysis (e.g., analytical values for multiple Method 29 
fractions both for individual HAP metals and for total HAP metals) may 
include a combination of method detection level data and analytical 
data reported above the method detection level.
    (2) If the limits are expressed in lb/MMBtu or lb/TBtu, you must 
use the F-factor methodology and equations in

[[Page 9473]]

sections 12.2 and 12.3 of EPA Method 19 in appendix A-7 to part 60 of 
this chapter. In cases where an appropriate F-factor is not listed in 
Table 19-2 of Method 19, you may use F-factors from Table 1 in section 
3.3.5 of appendix F to part 75 of this chapter, or F-factors derived 
using the procedures in section 3.3.6 of appendix to part 75 of this 
chapter. Use the following factors to convert the pollutant 
concentrations measured during the initial performance tests to units 
of lb/scf, for use in the applicable Method 19 equations:
    (i) Multiply SO2 ppm by 1.66 x 10-7;
    (ii) Multiply HCl ppm by 9.43 x 10-8;
    (iii) Multiply HF ppm by 5.18 x 10-8;
    (iv) Multiply HAP metals concentrations (mg/dscm) by 6.24 x 
10-8; and
    (v) Multiply Hg concentrations ([micro]g/scm) by 6.24 x 
10-11.
    (3) To determine compliance with emission limits expressed in lb/
MWh or lb/GWh, you must first calculate the pollutant mass emission 
rate during the performance test, in units of lb/h. For Hg, if a CEMS 
or sorbent trap monitoring system is used, use Equation A-2 or A-3 in 
appendix A to this subpart (as applicable). In all other cases, use an 
equation that has the general form of Equation A-2 or A-3, replacing 
the value of K with 1.66 x 10-7 lb/scf-ppm for 
SO2, 9.43 x 10-8 lb/scf-ppm for HCl (if an HCl 
CEMS is used), 5.18 x 10-8 lb/scf-ppm for HF (if an HF CEMS 
is used), or 6.24 x 10-8 lb-scm/mg-scf for HAP metals and 
for HCl and HF (when performance stack testing is used), and defining 
Ch as the average SO2, HCl, or HF concentration 
in ppm, or the average HAP metals concentration in mg/dscm. This 
calculation requires stack gas volumetric flow rate (scfh) and (in some 
cases) moisture content data (see Sec. Sec.  63.10005(h)(3) and 
63.10010). Then, if the applicable emission limit is in units of lb/
GWh, use Equation A-4 in appendix A to this subpart to calculate the 
pollutant emission rate in lb/GWh. In this calculation, define 
(M)h as the calculated pollutant mass emission rate for the 
performance test (lb/h), and define (MW)h as the average 
electrical load during the performance test (megawatts). If the 
applicable emission limit is in lb/MWh rather than lb/GWh, omit the 
103 term from Equation A-4 to determine the pollutant 
emission rate in lb/MWh.
    (f) Upon request, you shall make available to the EPA Administrator 
such records as may be necessary to determine whether the performance 
tests have been done according to the requirements of this section.


Sec.  63.10008  [Reserved]


Sec.  63.10009  May I use emissions averaging to comply with this 
subpart?

    (a) General eligibility. (1) You may use emissions averaging as 
described in paragraph (a)(2) of this section as an alternative to 
meeting the requirements of Sec.  63.9991 for filterable PM, 
SO2, HF, HCl, non-Hg HAP metals, or Hg on an EGU-specific 
basis if:
    (i) You have more than one existing EGU in the same subcategory 
located at one or more contiguous properties, belonging to a single 
major industrial grouping, which are under common control of the same 
person (or persons under common control); and
    (ii) You use CEMS (or sorbent trap monitoring systems for 
determining Hg emissions) or quarterly emissions testing for 
demonstrating compliance.
    (2) You may demonstrate compliance by emissions averaging among the 
existing EGUs in the same subcategory, if your averaged Hg emissions 
for EGUs in the ``unit designed for coal >= 8,300 Btu/lb'' subcategory 
are equal to or less than 1.0 lb/TBtu or 1.1E-2 lb/GWh or if your 
averaged emissions of individual, other pollutants from other 
subcategories of such EGUs are equal to or less than the applicable 
emissions limit in Table 2, according to the procedures in this 
section. Note that except for Hg emissions from EGUs in the ``unit 
designed for coal >= 8,300 Btu/lb'' subcategory, the averaging time for 
emissions averaging for pollutants is 30 days (rolling daily) using 
data from CEMS or a combination of data from CEMS and manual 
performance testing. The averaging time for emissions averaging for Hg 
from EGUs in the ``unit designed for coal >= 8,300 Btu/lb'' subcategory 
is 90 days (rolling daily) using data from CEMS, sorbent trap 
monitoring, or a combination of monitoring data and data from manual 
performance testing. For the purposes of this paragraph, 30- (or 90-
day) group boiler operating days is defined as a period during which at 
least one unit in the emissions averaging group has operated 30 (or 90) 
days. You must calculate the weighted average emissions rate for the 
group in accordance with the procedures in this paragraph using the 
data from all units in the group including any that operate fewer than 
30 (or 90) days during the preceding 30 (or 90) group boiler days.
    (i) You may choose to have your EGU emissions averaging group meet 
either the heat input basis (MMBtu or TBtu, as appropriate for the 
pollutant) or gross electrical output basis (MWh or GWh, as appropriate 
for the pollutant).
    (ii) You may not mix bases within your EGU emissions averaging 
group.
    (iii) You may use emissions averaging for affected units in 
different subcategories if the units vent to the atmosphere through a 
common stack (see paragraph (m) of this section).
    (b) Equations. Use the following equations when performing 
calculations for your EGU emissions averaging group:
    (1) Group eligibility equations.
    [GRAPHIC] [TIFF OMITTED] TR16FE12.003
    

Where:
WAERm = Weighted average emissions rate maximum in terms of lb/heat 
input or lb/gross electrical output,
Hermi = Hourly emissions rate (e.g., lb/MMBtu, lb/MWh) 
from CEMS or sorbent trap monitoring for hour i,
Rmmi = Maximum rated heat input or gross electrical 
output of unit i in terms of heat input or gross electrical output,
p = number of EGUs in emissions averaging group that rely on CEMS,
n = number of hourly rates collected over 30-group boiler operating 
days,
Teri = Emissions rate from most recent test of unit i in 
terms of lb/heat input or lb/gross electrical output,
Rmti = Maximum rated heat input or gross electrical 
output of unit i in terms of lb/heat input or lb/gross electrical 
output, and
m = number of EGUs in emissions averaging group that rely on 
emissions testing.

[[Page 9474]]

[GRAPHIC] [TIFF OMITTED] TR16FE12.004

Where:

variables with similar names share the descriptions for Equation 1a,
Smmi = maximum steam generation in units of pounds from 
unit i that uses CEMS or sorbent trap monitoring,
Cfmi = conversion factor, calculated from the most recent 
emissions test results, in units of heat input per pound of steam 
generated or gross electrical output per pound of steam generated, 
from unit i that uses CEMS or sorbent trap monitoring,
Smti = maximum steam generation in units of pounds from 
unit i that uses emissions testing, and
Cfti = conversion factor, calculated from the most recent 
emissions test results, in units of heat input per pound of steam 
generated or gross electrical output per pound of steam generated, 
from unit i that uses emissions testing.

    (2) Weighted 30-day rolling average emissions rate equations for 
pollutants other than Hg. Use equation 2a or 2b to calculate the 30-day 
rolling average emissions daily.
[GRAPHIC] [TIFF OMITTED] TR16FE12.005

Where:

Heri = hourly emission rate (e.g., lb/MMBtu, lb/MWh) from 
unit i's CEMS for the preceding 30-group boiler operating days,
Rmi = hourly heat input or gross electrical output from 
unit i for the preceding 30-group boiler operating days,
p = number of EGUs in emissions averaging group that rely on CEMS or 
sorbent trap monitoring,
n = number of hourly rates collected over 30-group boiler operating 
days,
Teri = Emissions rate from most recent emissions test of 
unit i in terms of lb/heat input or lb/gross electrical output,
Rti = Maximum rated heat input or gross electrical output 
of unit i in terms of lb/heat input or lb/gross electrical output, 
and
m = number of EGUs in emissions averaging group that rely on 
emissions testing.
[GRAPHIC] [TIFF OMITTED] TR16FE12.006

Where:

variables with similar names share the descriptions for Equation 2a,
Smi = steam generation in units of pounds from unit i 
that uses CEMS for the preceding 30-group boiler operating days,
Cfmi = conversion factor, calculated from the most recent 
compliance test results, in units of heat input per pound of steam 
generated or gross electrical output per pound of steam generated, 
from unit i that uses CEMS from the preceding 30-group boiler 
operating days,
Sti = steam generation in units of pounds from unit i 
that uses emissions testing, and
Cfti = conversion factor, calculated from the most recent 
compliance test results, in units of heat input per pound of steam 
generated or gross electrical output per pound of steam generated, 
from unit i that uses emissions testing.

    (3) Weighted 90-boiler operating day rolling average emissions rate 
equations for Hg emissions from EGUs in the ``unit designed for coal >= 
8,300 Btu/lb'' subcategory. Use equation 3a or 3b to calculate the 90-
day rolling average emissions daily.
[GRAPHIC] [TIFF OMITTED] TR16FE12.007

Where:

Heri = hourly emission rate from unit i's CEMS or Hg 
sorbent trap monitoring for the preceding 90-group boiler operating 
days,
Rmi = hourly heat input or gross electrical output from 
unit i for the preceding 90-group boiler operating days,
p = number of EGUs in emissions averaging group that rely on CEMS,
n = number of hourly rates collected over the 90-group boiler 
operating days,
Teri = Emissions rate from most recent emissions test of 
unit i in terms of lb/heat input or lb/gross electrical output,
Rti = Maximum rated heat input or gross electrical output 
of unit i in terms of lb/heat input or lb/gross electrical output, 
and
m = number of EGUs in emissions averaging group that rely on 
emissions testing.
[GRAPHIC] [TIFF OMITTED] TR16FE12.008


[[Page 9475]]


Where:

variables with similar names share the descriptions for Equation 2a,
Smi = steam generation in units of pounds from unit i 
that uses CEMS or a Hg sorbent trap monitoring for the preceding 90-
group boiler operating days,
Cfmi = conversion factor, calculated from the most recent 
compliance test results, in units of heat input per pound of steam 
generated or gross electrical output per pound of steam generated, 
from unit i that uses CEMS or sorbent trap monitoring from the 
preceding 90-group boiler operating days,
Sti = steam generation in units of pounds from unit i 
that uses emissions testing, and
Cfti = conversion factor, calculated from the most recent 
emissions test results, in units of heat input per pound of steam 
generated or gross electrical output per pound of steam generated, 
from unit i that uses emissions testing.

    (c) Separate stack requirements. For a group of two or more 
existing EGUs in the same subcategory that each vent to a separate 
stack, you may average filterable PM, SO2, HF, HCl, non-Hg 
HAP metals, or Hg emissions to demonstrate compliance with the limits 
in Table 2 to this subpart if you satisfy the requirements in 
paragraphs (d) through (j) of this section.
    (d) For each existing EGU in the averaging group:
    (1) The emissions rate achieved during the initial performance test 
for the HAP being averaged must not exceed the emissions level that was 
being achieved 180 days after April 16, 2015, or the date on which 
emissions testing done to support your emissions averaging plan is 
complete (if the Administrator does not require submission and approval 
of your emissions averaging plan), or the date that you begin emissions 
averaging, whichever is earlier; or
    (2) The control technology employed during the initial performance 
test must not be less than the design efficiency of the emissions 
control technology employed 180 days after April 16, 2015 or the date 
that you begin emissions averaging, whichever is earlier.
    (e) The weighted-average emissions rate from the existing EGUs 
participating in the emissions averaging option must be in compliance 
with the limits in Table 2 to this subpart at all times following the 
compliance date specified 180 days after April 16, 2015, or the date on 
which you complete the emissions measurements used to support your 
emissions averaging plan (if the Administrator does not require 
submission and approval of your emissions averaging plan), or the date 
that you begin emissions averaging, whichever is earlier.
    (f) Emissions averaging group eligibility demonstration. You must 
demonstrate the ability for the EGUs included in the emissions 
averaging group to demonstrate initial compliance according to 
paragraph (f)(1) or (2) of this section using the maximum normal 
operating load of each EGU and the results of the initial performance 
tests. For this demonstration and prior to submitting your emissions 
averaging plan, if requested, you must conduct required emissions 
monitoring for 30 days of boiler operation and any required manual 
performance testing to calculate an initial weighted average emissions 
rate in accordance with this section. Should the Administrator require 
approval, you must submit your proposed emissions averaging plan and 
supporting data at least 120 days before April 16, 2015. If the 
Administrator requires approval of your plan, you may not begin using 
emissions averaging until the Administrator approves your plan.
    (1) You must use Equation 1a in paragraph (b) of this section to 
demonstrate that the maximum weighted average emissions rates of 
filterable PM, HF, SO2, HCl, non-Hg HAP metals, or Hg 
emissions from the existing units participating in the emissions 
averaging option do not exceed the emissions limits in Table 2 to this 
subpart.
    (2) If you are not capable of monitoring heat input or gross 
electrical output, and the EGU generates steam for purposes other than 
generating electricity, you may use Equation 1b of this section as an 
alternative to using Equation 1a of this section to demonstrate that 
the maximum weighted average emissions rates of filterable PM, HF, 
SO2, HCl, non-Hg HAP metals, or Hg emissions from the 
existing units participating in the emissions averaging group do not 
exceed the emission limits in Table 2 to this subpart.
    (g) You must determine the weighted average emissions rate in units 
of the applicable emissions limit on a 30 day rolling average (90 day 
rolling average for Hg) basis according to paragraphs (f)(1) through 
(3) of this section. The first averaging period begins on 30 (or 90 for 
Hg) days after February 16, 2015 or the date that you begin emissions 
averaging, whichever is earlier.
    (1) You must use Equation 2a or 3a of paragraph (b) of this section 
to calculate the weighted average emissions rate using the actual heat 
input or gross electrical output for each existing unit participating 
in the emissions averaging option.
    (2) If you are not capable of monitoring heat input or gross 
electrical output, you may use Equation 2b or 3b of paragraph (b) of 
this section as an alternative to using Equation 2a of paragraph (b) of 
this section to calculate the average weighted emission rate using the 
actual steam generation from the units participating in the emissions 
averaging option.
    (h) CEMS (or sorbent trap monitoring) use. If an EGU in your 
emissions averaging group uses CEMS (or a sorbent trap monitor for Hg 
emissions) to demonstrate compliance, you must use those data to 
determine the 30 (or 90) group boiler operating day rolling average 
emissions rate.
    (i) Emissions testing. If you use manual emissions testing to 
demonstrate compliance for one or more EGUs in your emissions averaging 
group, you must use the results from the most recent performance test 
to determine the 30 (or 90) day rolling average. You may use CEMS or 
sorbent trap data in combination with data from the most recent manual 
performance test in calculating the 30 (or 90) group boiler operating 
day rolling average emissions rate.
    (j) Emissions averaging plan. You must develop an implementation 
plan for emissions averaging according to the following procedures and 
requirements in paragraphs (j)(1) and (2) of this section.
    (1) You must include the information contained in paragraphs 
(j)(1)(i) through (v) of this section in your implementation plan for 
all the emissions units included in an emissions averaging:
    (i) The identification of all existing EGUs in the emissions 
averaging group, including for each either the applicable HAP emission 
level or the control technology installed as of 180 days after February 
16, 2015, or the date on which you complete the emissions measurements 
used to support your emissions averaging plan (if the Administrator 
does not require submission and approval of your emissions averaging 
plan), or the date that you begin emissions averaging, whichever is 
earlier; and the date on which you are requesting emissions averaging 
to commence;
    (ii) The process weighting parameter (heat input, gross electrical 
output, or steam generated) that will be monitored for each averaging 
group;
    (iii) The specific control technology or pollution prevention 
measure to be used for each emission EGU in the averaging group and the 
date of its installation or application. If the pollution prevention 
measure reduces or eliminates

[[Page 9476]]

emissions from multiple EGUs, you must identify each EGU;
    (iv) The means of measurement (e.g., CEMS, sorbent trap monitoring, 
manual performance test) of filterable PM, SO2, HF, HCl, 
individual or total non-Hg HAP metals, or Hg emissions in accordance 
with the requirements in Sec.  63.10007 and to be used in the emissions 
averaging calculations; and
    (v) A demonstration that emissions averaging can produce compliance 
with each of the applicable emission limit(s) in accordance with 
paragraph (b)(1) of this section.
    (2) If the Administrator requests you to submit the plan for review 
and approval, you must submit a complete implementation plan at least 
120 days before April 16, 2015. If the Administrator requests you to 
submit the plan for review and approval, you must receive approval 
before initiating emissions averaging.
    (i) The Administrator shall use following criteria in reviewing and 
approving or disapproving the plan:
    (A) Whether the content of the plan includes all of the information 
specified in paragraph (h)(1) of this section; and
    (B) Whether the plan presents information sufficient to determine 
that compliance will be achieved and maintained.
    (ii) The Administrator shall not approve an emissions averaging 
implementation plan containing any of the following provisions:
    (A) Any averaging between emissions of different pollutants or 
between units located at different facilities; or
    (B) The inclusion of any emissions unit other than an existing unit 
in the same subcategory.
    (k) Common stack requirements. For a group of two or more existing 
affected units, each of which vents through a single common stack, you 
may average emissions to demonstrate compliance with the limits in 
Table 2 to this subpart if you satisfy the requirements in paragraph 
(l) or (m) of this section.
    (l) For a group of two or more existing units in the same 
subcategory and which vent through a common emissions control system to 
a common stack that does not receive emissions from units in other 
subcategories or categories, you may treat such averaging group as a 
single existing unit for purposes of this subpart and comply with the 
requirements of this subpart as if the group were a single unit.
    (m) For all other groups of units subject to paragraph (k) of this 
section, you may elect to conduct manual performance tests according to 
procedures specified in Sec.  63.10007 in the common stack. If 
emissions from affected units included in the emissions averaging and 
from other units not included in the emissions averaging (e.g., in a 
different subcategory) or other nonaffected units all vent to the 
common stack, you must shut down the units not included in the 
emissions averaging and the nonaffected units or vent their emissions 
to a different stack during the performance test. Alternatively, you 
may conduct a performance test of the combined emissions in the common 
stack with all units operating and show that the combined emissions 
meet the most stringent emissions limit. You may also use a CEMS or 
sorbent trap monitoring to apply this latter alternative to demonstrate 
that the combined emissions comply with the most stringent emissions 
limit on a continuous basis.
    (n) Combination requirements. The common stack of a group of two or 
more existing EGUs in the same subcategory subject to paragraph (k) of 
this section may be treated as a single stack for purposes of paragraph 
(c) of this section and included in an emissions averaging group 
subject to paragraph (c) of this section.


Sec.  63.10010  What are my monitoring, installation, operation, and 
maintenance requirements?

    (a) Flue gases from the affected units under this subpart exhaust 
to the atmosphere through a variety of different configurations, 
including but not limited to individual stacks, a common stack 
configuration or a main stack plus a bypass stack. For the CEMS, PM 
CPMS, and sorbent trap monitoring systems used to provide data under 
this subpart, the continuous monitoring system installation 
requirements for these exhaust configurations are as follows:
    (1) Single unit-single stack configurations. For an affected unit 
that exhausts to the atmosphere through a single, dedicated stack, you 
shall either install the required CEMS, PM CPMS, and sorbent trap 
monitoring systems in the stack or at a location in the ductwork 
downstream of all emissions control devices, where the pollutant and 
diluents concentrations are representative of the emissions that exit 
to the atmosphere.
    (2) Unit utilizing common stack with other affected unit(s). When 
an affected unit utilizes a common stack with one or more other 
affected units, but no non-affected units, you shall either:
    (i) Install the required CEMS, PM CPMS, and sorbent trap monitoring 
systems in the duct leading to the common stack from each unit; or
    (ii) Install the required CEMS, PM CPMS, and sorbent trap 
monitoring systems in the common stack.
    (3) Unit(s) utilizing common stack with non-affected unit(s).
    (i) When one or more affected units shares a common stack with one 
or more non-affected units, you shall either:
    (A) Install the required CEMS, PM CPMS, and sorbent trap monitoring 
systems in the ducts leading to the common stack from each affected 
unit; or
    (B) Install the required CEMS, PM CPMS, and sorbent trap monitoring 
systems described in this section in the common stack and attribute all 
of the emissions measured at the common stack to the affected unit(s).
    (ii) If you choose the common stack monitoring option:
    (A) For each hour in which valid data are obtained for all 
parameters, you must calculate the pollutant emission rate and
    (B) You must assign the calculated pollutant emission rate to each 
unit that shares the common stack.
    (4) Unit with a main stack and a bypass stack. If the exhaust 
configuration of an affected unit consists of a main stack and a bypass 
stack, you shall install CEMS on both the main stack and the bypass 
stack, or, if it is not feasible to certify and quality-assure the data 
from a monitoring system on the bypass stack, you shall install a CEMS 
only on the main stack and count bypass hours of deviation from the 
monitoring requirements.
    (5) Unit with a common control device with multiple stack or duct 
configuration. If the flue gases from an affected unit, which is 
configured such that emissions are controlled with a common control 
device or series of control devices, are discharged to the atmosphere 
through more than one stack or are fed into a single stack through two 
or more ducts, you may:
    (i) Install required CEMS, PM CPMS, and sorbent trap monitoring 
systems in each of the multiple stacks;
    (ii) Install required CEMS, PM CPMS, and sorbent trap monitoring 
systems in each of the ducts that feed into the stack;
    (iii) Install required CEMS, PM CPMS, and sorbent trap monitoring 
systems in one of the multiple stacks or ducts and monitor the flows 
and dilution rates in all multiple stacks or ducts in order to 
determine total exhaust gas flow rate and pollutant mass emissions rate 
in accordance with the applicable limit; or
    (iv) In the case of multiple ducts feeding into a single stack, 
install CEMS, PM CPMS, and sorbent trap

[[Page 9477]]

monitoring systems in the single stack as described in paragraph (a)(1) 
of this section.
    (6) Unit with multiple parallel control devices with multiple 
stacks. If the flue gases from an affected unit, which is configured 
such that emissions are controlled with multiple parallel control 
devices or multiple series of control devices are discharged to the 
atmosphere through more than one stack, you shall install the required 
CEMS, PM CPMS, and sorbent trap monitoring systems described in each of 
the multiple stacks. You shall calculate hourly flow-weighted average 
pollutant emission rates for the unit as follows:
    (i) Calculate the pollutant emission rate at each stack or duct for 
each hour in which valid data are obtained for all parameters;
    (ii) Multiply each calculated hourly pollutant emission rate at 
each stack or duct by the corresponding hourly stack gas flow rate at 
that stack or duct;
    (iii) Sum the products determined under paragraph (a)(5)(iii)(B) of 
this section; and
    (iv) Divide the result obtained in paragraph (a)(5)(iii)(C) of this 
section by the total hourly stack gas flow rate for the unit, summed 
across all of the stacks or ducts.
    (b) If you use an oxygen (O2) or carbon dioxide 
(CO2) CEMS to convert measured pollutant concentrations to 
the units of the applicable emissions limit, the O2 or 
CO2 concentrations shall be monitored at a location that 
represents emissions to the atmosphere, i.e., at the outlet of the EGU, 
downstream of all emission control devices. You must install, certify, 
maintain, and operate the CEMS according to part 75 of this chapter. 
Use only quality-assured O2 or CO2 data in the 
emissions calculations; do not use part 75 substitute data values.
    (c) If you are required to use a stack gas flow rate monitor, 
either for routine operation of a sorbent trap monitoring system or to 
convert pollutant concentrations to units of an electrical output-based 
emission standard in Table 1 or 2 to this subpart, you must install, 
certify, operate, and maintain the monitoring system and conduct on-
going quality-assurance testing of the system according to part 75 of 
this chapter. Use only unadjusted, quality-assured flow rate data in 
the emissions calculations. Do not apply bias adjustment factors to the 
flow rate data and do not use substitute flow rate data in the 
calculations.
    (d) If you are required to make corrections for stack gas moisture 
content when converting pollutant concentrations to the units of an 
emission standard in Table 1 of 2 to this subpart, you must install, 
certify, operate, and maintain a moisture monitoring system in 
accordance with part 75 of this chapter. Alternatively, for coal-fired 
units, you may use appropriate fuel-specific default moisture values 
from Sec.  75.11(b) of this chapter to estimate the moisture content of 
the stack gas or you may petition the Administrator under Sec.  75.66 
of this chapter for use of a default moisture value for non-coal-fired 
units. If you install and operate a moisture monitoring system, do not 
use substitute moisture data in the emissions calculations.
    (e) If you use an HCl and/or HF CEMS, you must install, certify, 
operate, maintain, and quality-assure the data from the monitoring 
system in accordance with appendix B to this subpart. Calculate and 
record a 30-boiler operating day rolling average HCl or HF emission 
rate in the units of the standard, updated after each new boiler 
operating day. Each 30-boiler operating day rolling average emission 
rate is the average of all the valid hourly HCl or HF emission rates in 
the preceding 30 boiler operating days (see section 9.4 of appendix B 
to this subpart).
    (f)(1) If you use an SO2 CEMS, you must install the 
monitor at the outlet of the EGU, downstream of all emission control 
devices, and you must certify, operate, and maintain the CEMS according 
to part 75 of this chapter.
    (2) For on-going QA, the SO2 CEMS must meet the 
applicable daily, quarterly, and semiannual or annual requirements in 
sections 2.1 through 2.3 of appendix B to part 75 of this chapter, with 
the following addition: You must perform the linearity checks required 
in section 2.2 of appendix B to part 75 of this chapter if the 
SO2 CEMS has a span value of 30 ppm or less.
    (3) Calculate and record a 30-boiler operating day rolling average 
SO2 emission rate in the units of the standard, updated 
after each new boiler operating day. Each 30-boiler operating day 
rolling average emission rate is the average of all of the valid 
SO2 emission rates in the preceding 30 boiler operating 
days.
    (4) Use only unadjusted, quality-assured SO2 
concentration values in the emissions calculations; do not apply bias 
adjustment factors to the part 75 SO2 data and do not use 
part 75 substitute data values.
    (g) If you use a Hg CEMS or a sorbent trap monitoring system, you 
must install, certify, operate, maintain and quality-assure the data 
from the monitoring system in accordance with appendix A to this 
subpart. You must calculate and record a 30-boiler operating day 
rolling average Hg emission rate, in units of the standard, updated 
after each new boiler operating day. Each 30-boiler operating day 
rolling average emission rate, calculated according to section 6.2 of 
appendix A to the subpart, is the average of all of the valid hourly Hg 
emission rates in the preceding 30 boiler operating days. Section 
7.1.4.3 of appendix A to this subpart explains how to reduce sorbent 
trap monitoring system data to an hourly basis.
    (h) If you use a PM CPMS to demonstrate continuous compliance with 
an operating limit, you must install, calibrate, maintain, and operate 
the PM CPMS and record the output of the system as specified in 
paragraphs (h)(1) through (5) of this section.
    (1) Install, calibrate, operate, and maintain your PM CPMS 
according to the procedures in your approved site-specific monitoring 
plan developed in accordance with Sec.  63.10000(d), and meet the 
requirements in paragraphs (h)(1)(i) through (iii) of this section.
    (i) The operating principle of the PM CPMS must be based on in-
stack or extractive light scatter, light scintillation, beta 
attenuation, or mass accumulation detection of the exhaust gas or 
representative sample. The reportable measurement output from the PM 
CPMS may be expressed as milliamps, stack concentration, or other raw 
data signal.
    (ii) The PM CPMS must have a cycle time (i.e., period required to 
complete sampling, measurement, and reporting for each measurement) no 
longer than 60 minutes.
    (iii) The PM CPMS must be capable, at a minimum, of detecting and 
responding to particulate matter concentrations of 0.5 mg/acm.
    (2) For a new unit, complete the initial PM CPMS performance 
evaluation no later than October 13, 2012 or 180 days after the date of 
initial startup, whichever is later. For an existing unit, complete the 
initial performance evaluation no later than October 13, 2015.
    (3) Collect PM CPMS hourly average output data for all boiler 
operating hours except as indicated in paragraph (h)(5) of this 
section. Express the PM CPMS output as milliamps, PM concentration, or 
other raw data signal value.
    (4) Calculate the arithmetic 30-boiler operating day rolling 
average of all of the hourly average PM CPMS output collected during 
all nonexempt boiler operating hours data (e.g., milliamps, PM 
concentration, raw data signal).

[[Page 9478]]

    (5) You must collect data using the PM CPMS at all times the 
process unit is operating and at the intervals specified in paragraph 
(h)(1)(ii) of this section, except for periods of monitoring system 
malfunctions, repairs associated with monitoring system malfunctions, 
required monitoring system quality assurance or quality control 
activities (including, as applicable, calibration checks and required 
zero and span adjustments), and any scheduled maintenance as defined in 
your site-specific monitoring plan.
    (6) You must use all the data collected during all boiler operating 
hours in assessing the compliance with your operating limit except:
    (i) Any data collected during monitoring system malfunctions, 
repairs associated with monitoring system malfunctions, or required 
monitoring system quality assurance or quality control activities 
conducted during monitoring system malfunctions are not used in 
calculations (report any such periods in your annual deviation report);
    (ii) Any data collected during periods when the monitoring system 
is out of control as specified in your site-specific monitoring plan, 
repairs associated with periods when the monitoring system is out of 
control, or required monitoring system quality assurance or quality 
control activities conducted during out-of-control periods are not used 
in calculations (report emissions or operating levels and report any 
such periods in your annual deviation report);
    (iii) Any data recorded during periods of startup or shutdown.
    (7) You must record and make available upon request results of PM 
CPMS system performance audits, as well as the dates and duration of 
periods from when the PM CPMS is out of control until completion of the 
corrective actions necessary to return the PM CPMS to operation 
consistent with your site-specific monitoring plan.
    (i) If you choose to comply with the PM filterable emissions limit 
in lieu of metal HAP limits, you may choose to install, certify, 
operate, and maintain a PM CEMS and record the output of the PM CEMS as 
specified in paragraphs (i)(1) through (5) of this section. The 
compliance limit will be expressed as a 30-boiler operating day rolling 
average of the numerical emissions limit value applicable for your unit 
in tables 1 or 2 to this subpart.
    (1) Install and certify your PM CEMS according to the procedures 
and requirements in Performance Specification 11--Specifications and 
Test Procedures for Particulate Matter Continuous Emission Monitoring 
Systems at Stationary Sources in Appendix B to part 60 of this chapter, 
using Method 5 at Appendix A-3 to part 60 of this chapter and ensuring 
that the front half filter temperature shall be 160[deg]  
14[deg]C (320[deg]  25[deg]F). The reportable measurement 
output from the PM CEMS must be expressed in units of the applicable 
emissions limit (e.g., lb/MMBtu, lb/MWh).
    (2) Operate and maintain your PM CEMS according to the procedures 
and requirements in Procedure 2--Quality Assurance Requirements for 
Particulate Matter Continuous Emission Monitoring Systems at Stationary 
Sources in Appendix F to part 60 of this chapter.
    (i) You must conduct the relative response audit (RRA) for your PM 
CEMS at least once annually.
    (ii) You must conduct the relative correlation audit (RCA) for your 
PM CEMS at least once every 3 years.
    (3) Collect PM CEMS hourly average output data for all boiler 
operating hours except as indicated in paragraph (i) of this section.
    (4) Calculate the arithmetic 30-boiler operating day rolling 
average of all of the hourly average PM CEMS output data collected 
during all nonexempt boiler operating hours.
    (5) You must collect data using the PM CEMS at all times the 
process unit is operating and at the intervals specified in paragraph 
(a) of this section, except for periods of monitoring system 
malfunctions, repairs associated with monitoring system malfunctions, 
and required monitoring system quality assurance or quality control 
activities.
    (i) You must use all the data collected during all boiler operating 
hours in assessing the compliance with your operating limit except:
    (A) Any data collected during monitoring system malfunctions, 
repairs associated with monitoring system malfunctions, or required 
monitoring system quality assurance or control activities conducted 
during monitoring system malfunctions in calculations and report any 
such periods in your annual deviation report;
    (B) Any data collected during periods when the monitoring system is 
out of control as specified in your site-specific monitoring plan, 
repairs associated with periods when the monitoring system is out of 
control, or required monitoring system quality assurance or control 
activities conducted during out of control periods in calculations used 
to report emissions or operating levels and report any such periods in 
your annual deviation report;
    (C) Any data recorded during periods of startup or shutdown.
    (ii) You must record and make available upon request results of PM 
CEMS system performance audits, dates and duration of periods when the 
PM CEMS is out of control to completion of the corrective actions 
necessary to return the PM CEMS to operation consistent with your site-
specific monitoring plan.
    (j) You may choose to comply with the metal HAP emissions limits 
using CEMS approved in accordance with Sec.  63.7(f) as an alternative 
to the performance test method specified in this rule. If approved to 
use a HAP metals CEMS, the compliance limit will be expressed as a 30-
boiler operating day rolling average of the numerical emissions limit 
value applicable for your unit in tables 1 or 2. If approved, you may 
choose to install, certify, operate, and maintain a HAP metals CEMS and 
record the output of the HAP metals CEMS as specified in paragraphs 
(j)(1) through (5) of this section.
    (1)(i) Install and certify your HAP metals CEMS according to the 
procedures and requirements in you approved site specific test plan as 
required in Sec.  63.7(e). The reportable measurement output from the 
HAP metals CEMS must be expressed in units of the applicable emissions 
limit (e.g., lb/MMBtu, lb/MWh) and in the form of a 30-boiler operating 
day rolling average.
    (ii) Operate and maintain your HAP metals CEMS according to the 
procedures and criteria in your site specific performance evaluation 
and quality control program plan required in Sec.  63.8(d).
    (2) Collect HAP metals CEMS hourly average output data for all 
boiler operating hours except as indicated in section (j)(4) of this 
section.
    (3) Calculate the arithmetic 30-boiler operating day rolling 
average of all of the hourly average HAP metals CEMS output data 
collected during all nonexempt boiler operating hours data.
    (4) You must collect data using the HAP metals CEMS at all times 
the process unit is operating and at the intervals specified in 
paragraph (a) of this section, except for periods of monitoring system 
malfunctions, repairs associated with monitoring system malfunctions, 
and required monitoring system quality assurance or quality control 
activities.
    (i) You must use all the data collected during all boiler operating 
hours in assessing the compliance with your emission limit except:
    (A) Any data collected during monitoring system malfunctions, 
repairs associated with monitoring system malfunctions, or required 
monitoring

[[Page 9479]]

system quality assurance or control activities conducted during 
monitoring system malfunctions in calculations and report any such 
periods in your annual deviation report;
    (B) Any data collected during periods when the monitoring system is 
out of control as specified in your site-specific monitoring plan, 
repairs associated with periods when the monitoring system is out of 
control, or required monitoring system quality assurance or control 
activities conducted during out of control periods in calculations used 
to report emissions or operating levels and report any such periods in 
your annual deviation report;
    (C) Any data recorded during periods of startup or shutdown.
    (ii) You must record and make available upon request results of HAP 
metals CEMS system performance audits, dates and duration of periods 
when the HAP metals CEMS is out of control to completion of the 
corrective actions necessary to return the HAP metals CEMS to operation 
consistent with your site-specific performance evaluation and quality 
control program plan.
    (k) If you demonstrate compliance with the HCl and HF emission 
limits for a liquid oil-fired EGU by conducting quarterly testing, you 
must also develop a site-specific monitoring plan as provided for in 
Sec.  63.10000(c)(2)(iii) and Table 7 to this subpart.


Sec.  63.10011  How do I demonstrate initial compliance with the 
emissions limits and work practice standards?

    (a) You must demonstrate initial compliance with each emissions 
limit that applies to you by conducting performance testing.
    (b) If you are subject to an operating limit in Table 4 to this 
subpart, you demonstrate initial compliance with HAP metals or 
filterable PM emission limit(s) through performance stack tests and you 
elect to use a PM CPMS to demonstrate continuous performance, or if, 
for a liquid oil-fired unit, and you use quarterly stack testing for 
HCl and HF plus site-specific parameter monitoring to demonstrate 
continuous performance, you must also establish a site-specific 
operating limit, in accordance with Table 4 to this subpart, Sec.  
63.10007, and Table 6 to this subpart. You may use only the parametric 
data recorded during successful performance tests (i.e., tests that 
demonstrate compliance with the applicable emissions limits) to 
establish an operating limit.
    (c)(1) If you use CEMS or sorbent trap monitoring systems to 
measure a HAP (e.g., Hg or HCl) directly, the first 30-boiler operating 
day rolling average emission rate obtained with certified CEMS after 
the applicable date in Sec.  63.9984 (or, if applicable, prior to that 
date, as described in Sec.  63.10005(b)(2)), expressed in units of the 
standard, is the initial performance test. Initial compliance is 
demonstrated if the results of the performance test meet the applicable 
emission limit in Table 1 or 2 to this subpart.
    (2) For a unit that uses a CEMS to measure SO2 or PM 
emissions for initial compliance, the first 30 boiler operating day 
average emission rate obtained with certified CEMS after the applicable 
date in Sec.  63.9984 (or, if applicable, prior to that date, as 
described in Sec.  63.10005(b)(2)), expressed in units of the standard, 
is the initial performance test. Initial compliance is demonstrated if 
the results of the performance test meet the applicable SO2 
or filterable PM emission limit in Table 1 or 2 to this subpart.
    (d) For candidate LEE units, use the results of the performance 
testing described in Sec.  63.10005(h) to determine initial compliance 
with the applicable emission limit(s) in Table 1 or 2 to this subpart 
and to determine whether the unit qualifies for LEE status.
    (e) You must submit a Notification of Compliance Status containing 
the results of the initial compliance demonstration, according to Sec.  
63.10030(e).
    (f)(1) You must determine the fuel whose combustion produces the 
least uncontrolled emissions, i.e., the cleanest fuel, either natural 
gas or distillate oil, that is available on site or accessible nearby 
for use during periods of startup or shutdown.
    (2) Your cleanest fuel, either natural gas or distillate oil, for 
use during periods of startup or shutdown determination may take safety 
considerations into account.
    (g) You must follow the startup or shutdown requirements given in 
Table 3 for each coal-fired, liquid oil-fired, and solid oil-derived 
fuel-fired EGU.

Continuous Compliance Requirements


Sec.  63.10020  How do I monitor and collect data to demonstrate 
continuous compliance?

    (a) You must monitor and collect data according to this section and 
the site-specific monitoring plan required by Sec.  63.10000(d).
    (b) You must operate the monitoring system and collect data at all 
required intervals at all times that the affected EGU is operating, 
except for periods of monitoring system malfunctions or out-of-control 
periods (see Sec.  63.8(c)(7) of this part), and required monitoring 
system quality assurance or quality control activities, including, as 
applicable, calibration checks and required zero and span adjustments. 
You are required to affect monitoring system repairs in response to 
monitoring system malfunctions and to return the monitoring system to 
operation as expeditiously as practicable.
    (c) You may not use data recorded during EGU startup or shutdown or 
monitoring system malfunctions or monitoring system out-of-control 
periods, repairs associated with monitoring system malfunctions or 
monitoring system out-of-control periods, or required monitoring system 
quality assurance or control activities in calculations used to report 
emissions or operating levels. You must use all the data collected 
during all other periods in assessing the operation of the control 
device and associated control system.
    (d) Except for periods of monitoring system malfunctions or 
monitoring system out-of-control periods, repairs associated with 
monitoring system malfunctions or monitoring system out-of-control 
periods, and required monitoring system quality assurance or quality 
control activities including, as applicable, calibration checks and 
required zero and span adjustments), failure to collect required data 
is a deviation of the monitoring requirements.


Sec.  63.10021  How do I demonstrate continuous compliance with the 
emission limitations, operating limits, and work practice standards?

    (a) You must demonstrate continuous compliance with each emissions 
limit, operating limit, and work practice standard in Tables 1 through 
4 to this subpart that applies to you, according to the monitoring 
specified in Tables 6 and 7 to this subpart and paragraphs (b) through 
(g) of this section.
    (b) Except as otherwise provided in Sec.  63.10020(c), if you use a 
CEMS to measure SO2, PM, HCl, HF, or Hg emissions, or using 
a sorbent trap monitoring system to measure Hg emissions, you must 
demonstrate continuous compliance by using all quality-assured hourly 
data recorded by the CEMS (or sorbent trap monitoring system) and the 
other required monitoring systems (e.g., flow rate, CO2, 
O2, or moisture systems) to calculate the arithmetic average 
emissions rate in units of the standard on a continuous 30-boiler 
operating day rolling average basis, updated at the end of each new 
boiler operating day. Use Equation 8 to determine the 30-boiler 
operating day rolling average.

[[Page 9480]]

[GRAPHIC] [TIFF OMITTED] TR16FE12.009

Where:

Heri is the hourly emissions rate for hour i and n is the 
number of hourly emissions rate values collected over 30 boiler 
operating days.

    (c) If you use a PM CPMS data to measure compliance with an 
operating limit in Table 4 to this subpart, you must record the PM CPMS 
output data for all periods when the process is operating and the PM 
CPMS is not out-of-control. You must demonstrate continuous compliance 
by using all quality-assured hourly average data collected by the PM 
CPMS for all operating hours to calculate the arithmetic average 
operating parameter in units of the operating limit (e.g., milliamps, 
PM concentration, raw data signal) on a 30 operating day rolling 
average basis, updated at the end of each new boiler operating day. Use 
Equation 9 to determine the 30 boiler operating day average.
[GRAPHIC] [TIFF OMITTED] TR16FE12.010

Where:

Hpvi is the hourly parameter value for hour i and n is 
the number of valid hourly parameter values collected over 30 boiler 
operating days.

    (d) If you use quarterly performance testing to demonstrate 
compliance with one or more applicable emissions limits in Table 1 or 2 
to this subpart, you
    (1) May skip performance testing in those quarters during which 
less than 168 boiler operating hours occur, except that a performance 
test must be conducted at least once every calendar year.
    (2) Must conduct the performance test as defined in Table 5 to this 
subpart and calculate the results of the testing in units of the 
applicable emissions standard; and
    (3) Must conduct site-specific monitoring for a liquid oil-fired 
unit to ensure compliance with the HCl and HF emission limits in Tables 
1 and 2 to this subpart, in accordance with the requirements of Sec.  
63.10000(c)(2)(iii). The monitoring must meet the general operating 
requirements provided in Sec.  63.10020(a).
    (e) If you must conduct periodic performance tune-ups of your 
EGU(s), as specified in paragraphs (e)(1) through (9) of this section, 
perform the first tune-up as part of your initial compliance 
demonstration. Notwithstanding this requirement, you may delay the 
first burner inspection until the next scheduled unit outage provided 
you meet the requirements of Sec.  63.10005. Subsequently, you must 
perform an inspection of the burner at least once every 36 calendar 
months unless your EGU employs neural network combustion optimization 
during normal operations in which case you must perform an inspection 
of the burner and combustion controls at least once every 48 calendar 
months.
    (1) As applicable, inspect the burner and combustion controls, and 
clean or replace any components of the burner or combustion controls as 
necessary upon initiation of the work practice program and at least 
once every required inspection period. Repair of a burner or combustion 
control component requiring special order parts may be scheduled as 
follows:
    (i) Burner or combustion control component parts needing 
replacement that affect the ability to optimize NOX and CO 
must be installed within 3 calendar months after the burner inspection,
    (ii) Burner or combustion control component parts that do not 
affect the ability to optimize NOX and CO may be installed 
on a schedule determined by the operator;
    (2) As applicable, inspect the flame pattern and make any 
adjustments to the burner or combustion controls necessary to optimize 
the flame pattern. The adjustment should be consistent with the 
manufacturer's specifications, if available, or in accordance with best 
combustion engineering practice for that burner type;
    (3) As applicable, observe the damper operations as a function of 
mill and/or cyclone loadings, cyclone and pulverizer coal feeder 
loadings, or other pulverizer and coal mill performance parameters, 
making adjustments and effecting repair to dampers, controls, mills, 
pulverizers, cyclones, and sensors;
    (4) As applicable, evaluate windbox pressures and air proportions, 
making adjustments and effecting repair to dampers, actuators, 
controls, and sensors;
    (5) Inspect the system controlling the air-to-fuel ratio and ensure 
that it is correctly calibrated and functioning properly. Such 
inspection may include calibrating excess O2 probes and/or 
sensors, adjusting overfire air systems, changing software parameters, 
and calibrating associated actuators and dampers to ensure that the 
systems are operated as designed. Any component out of calibration, in 
or near failure, or in a state that is likely to negate combustion 
optimization efforts prior to the next tune-up, should be corrected or 
repaired as necessary;
    (6) Optimize combustion to minimize generation of CO and 
NOX. This optimization should be consistent with the 
manufacturer's specifications, if available, or best combustion 
engineering practice for the applicable burner type. NOX 
optimization includes burners, overfire air controls, concentric firing 
system improvements, neural network or combustion efficiency software, 
control systems calibrations, adjusting combustion zone temperature 
profiles, and add-on controls such as SCR and SNCR; CO optimization 
includes burners, overfire air controls, concentric firing system 
improvements, neural network or combustion efficiency software, control 
systems calibrations, and adjusting combustion zone temperature 
profiles;
    (7) While operating at full load or the predominantly operated 
load, measure the concentration in the effluent stream of CO and 
NOX in ppm, by volume, and oxygen in volume percent, before 
and after the tune-up adjustments are made (measurements may be either 
on a dry or wet basis, as long as it is the same basis before and after 
the adjustments are made). You may use portable CO, NOX and 
O2 monitors for this measurement. EGU's employing neural 
network optimization systems need only provide a single pre- and post-
tune-up value rather than continual values before and after each 
optimization adjustment made by the system;
    (8) Maintain on-site and submit, if requested by the Administrator, 
an annual report containing the information in paragraphs (e)(1) 
through (e)(9) of this section including:

[[Page 9481]]

    (i) The concentrations of CO and NOX in the effluent 
stream in ppm by volume, and oxygen in volume percent, measured before 
and after an adjustment of the EGU combustion systems;
    (ii) A description of any corrective actions taken as a part of the 
combustion adjustment; and
    (iii) The type(s) and amount(s) of fuel used over the 12 calendar 
months prior to an adjustment, but only if the unit was physically and 
legally capable of using more than one type of fuel during that period; 
and
    (9) Report the dates of the initial and subsequent tune-ups as 
follows:
    (i) If the first required tune-up is performed as part of the 
initial compliance demonstration, report the date of the tune-up in 
hard copy (as specified in Sec.  63.10030) and electronically (as 
specified in Sec.  63.10031). Report the date of each subsequent tune-
up electronically (as specified in Sec.  63.10031).
    (ii) If the first tune-up is not conducted as part of the initial 
compliance demonstration, but is postponed until the next unit outage, 
report the date of that tune-up and all subsequent tune-ups 
electronically, in accordance with Sec.  63.10031.
    (f) You must submit the reports required under Sec.  63.10031 and, 
if applicable, the reports required under appendices A and B to this 
subpart. The electronic reports required by appendices A and B to this 
subpart must be sent to the Administrator electronically in a format 
prescribed by the Administrator, as provided in Sec.  63.10031. CEMS 
data (except for PM CEMS and any approved alternative monitoring using 
a HAP metals CEMS) shall be submitted using EPA's Emissions Collection 
and Monitoring Plan System (ECMPS) Client Tool. Other data, including 
PM CEMS data, HAP metals CEMS data, and CEMS performance test detail 
reports, shall be submitted in the file format generated through use of 
EPA's Electronic Reporting Tool, the Compliance and Emissions Data 
Reporting Interface, or alternate electronic file format, all as 
provided for under Sec.  63.10031.
    (g) You must report each instance in which you did not meet an 
applicable emissions limit or operating limit in Tables 1 through 4 to 
this subpart or failed to conduct a required tune-up. These instances 
are deviations from the requirements of this subpart. These deviations 
must be reported according to Sec.  63.10031.
    (h) You must keep records as specified in Sec.  63.10032 during 
periods of startup and shutdown.
    (i) You must provide reports as specified in Sec.  63.10031 
concerning activities and periods of startup and shutdown.


Sec.  63.10022  How do I demonstrate continuous compliance under the 
emissions averaging provision?

    (a) Following the compliance date, the owner or operator must 
demonstrate compliance with this subpart on a continuous basis by 
meeting the requirements of paragraphs (a)(1) through (3) of this 
section.
    (1) For each calendar month, demonstrate compliance with the 
average weighted emissions limit for the existing units participating 
in the emissions averaging option as determined in Sec.  63.10009(f) 
and (g);
    (2) For each existing unit participating in the emissions averaging 
option that is equipped with PM CPMS, maintain the average parameter 
value at or below the operating limit established during the most 
recent performance test;
    (3) For each existing unit participating in the emissions averaging 
option venting to a common stack configuration containing affected 
units from other subcategories, maintain the appropriate operating 
limit for each unit as specified in Table 4 to this subpart that 
applies.
    (b) Any instance where the owner or operator fails to comply with 
the continuous monitoring requirements in paragraphs (a)(1) through (3) 
of this section is a deviation.


Sec.  63.10023  How do I establish my PM CPMS operating limit and 
determine compliance with it?

    (a) During the initial performance test or any such subsequent 
performance test that demonstrates compliance with the filterable PM, 
individual non-mercury HAP metals, or total non-mercury HAP metals 
limit (or for liquid oil-fired units, individual HAP metals or total 
HAP metals limit, including Hg) in Table 1 or 2, record all hourly 
average output values (e.g., milliamps, stack concentration, or other 
raw data signal) from the PM CPMS for the periods corresponding to the 
test runs (e.g., nine 1-hour average PM CPMS output values for three 3-
hour test runs).
    (b) Determine your operating limit as the highest 1-hour average PM 
CPMS output value recorded during the performance test. You must verify 
an existing or establish a new operating limit after each repeated 
performance test.
    (c) You must operate and maintain your process and control 
equipment such that the 30 operating day average PM CPMS output does 
not exceed the operating limit determined in paragraphs (a) and (b) of 
this section.

Notification, Reports, and Records


Sec.  63.10030  What notifications must I submit and when?

    (a) You must submit all of the notifications in Sec. Sec.  63.7(b) 
and (c), 63.8 (e), (f)(4) and (6), and 63.9 (b) through (h) that apply 
to you by the dates specified.
    (b) As specified in Sec.  63.9(b)(2), if you startup your affected 
source before April 16, 2012, you must submit an Initial Notification 
not later than 120 days after April 16, 2012.
    (c) As specified in Sec.  63.9(b)(4) and (b)(5), if you startup 
your new or reconstructed affected source on or after April 16, 2012, 
you must submit an Initial Notification not later than 15 days after 
the actual date of startup of the affected source.
    (d) When you are required to conduct a performance test, you must 
submit a Notification of Intent to conduct a performance test at least 
30 days before the performance test is scheduled to begin.
    (e) When you are required to conduct an initial compliance 
demonstration as specified in Sec.  63.10011(a), you must submit a 
Notification of Compliance Status according to Sec.  63.9(h)(2)(ii). 
The Notification of Compliance Status report must contain all the 
information specified in paragraphs (e)(1) through (7), as applicable.
    (1) A description of the affected source(s) including 
identification of which subcategory the source is in, the design 
capacity of the source, a description of the add-on controls used on 
the source, description of the fuel(s) burned, including whether the 
fuel(s) were determined by you or EPA through a petition process to be 
a non-waste under 40 CFR 241.3, whether the fuel(s) were processed from 
discarded non-hazardous secondary materials within the meaning of 40 
CFR 241.3, and justification for the selection of fuel(s) burned during 
the performance test.
    (2) Summary of the results of all performance tests and fuel 
analyses and calculations conducted to demonstrate initial compliance 
including all established operating limits.
    (3) Identification of whether you plan to demonstrate compliance 
with each applicable emission limit through performance testing; fuel 
moisture analyses; performance testing with operating limits (e.g., use 
of PM CPMS); CEMS; or a sorbent trap monitoring system.
    (4) Identification of whether you plan to demonstrate compliance by 
emissions averaging.

[[Page 9482]]

    (5) A signed certification that you have met all applicable 
emission limits and work practice standards.
    (6) If you had a deviation from any emission limit, work practice 
standard, or operating limit, you must also submit a brief description 
of the deviation, the duration of the deviation, emissions point 
identification, and the cause of the deviation in the Notification of 
Compliance Status report.
    (7) In addition to the information required in Sec.  63.9(h)(2), 
your notification of compliance status must include the following:
    (i) A summary of the results of the annual performance tests and 
documentation of any operating limits that were reestablished during 
this test, if applicable. If you are conducting stack tests once every 
3 years consistent with Sec.  63.10006(i), the date of the last three 
stack tests, a comparison of the emission level you achieved in the 
last three stack tests to the 50 percent emission limit threshold 
required in Sec.  63.10006(i), and a statement as to whether there have 
been any operational changes since the last stack test that could 
increase emissions.
    (ii) Certifications of compliance, as applicable, and must be 
signed by a responsible official stating:
    (A) ``This EGU complies with the requirements in Sec.  63.10021(a) 
to demonstrate continuous compliance.'' and
    (B) ``No secondary materials that are solid waste were combusted in 
any affected unit.''


Sec.  63.10031  What reports must I submit and when?

    (a) You must submit each report in Table 8 to this subpart that 
applies to you. If you are required to (or elect to) continuously 
monitor Hg and/or HCl and/or HF emissions, you must also submit the 
electronic reports required under appendix A and/or appendix B to the 
subpart, at the specified frequency.
    (b) Unless the Administrator has approved a different schedule for 
submission of reports under Sec.  63.10(a), you must submit each report 
by the date in Table 8 to this subpart and according to the 
requirements in paragraphs (b)(1) through (5) of this section.
    (1) The first compliance report must cover the period beginning on 
the compliance date that is specified for your affected source in Sec.  
63.9984 and ending on June 30 or December 31, whichever date is the 
first date that occurs at least 180 days after the compliance date that 
is specified for your source in Sec.  63.9984.
    (2) The first compliance report must be postmarked or submitted 
electronically no later than July 31 or January 31, whichever date is 
the first date following the end of the first calendar half after the 
compliance date that is specified for your source in Sec.  63.9984.
    (3) Each subsequent compliance report must cover the semiannual 
reporting period from January 1 through June 30 or the semiannual 
reporting period from July 1 through December 31.
    (4) Each subsequent compliance report must be postmarked or 
submitted electronically no later than July 31 or January 31, whichever 
date is the first date following the end of the semiannual reporting 
period.
    (5) For each affected source that is subject to permitting 
regulations pursuant to part 70 or part 71 of this chapter, and if the 
permitting authority has established dates for submitting semiannual 
reports pursuant to 40 CFR 70.6(a)(3)(iii)(A) or 40 CFR 
71.6(a)(3)(iii)(A), you may submit the first and subsequent compliance 
reports according to the dates the permitting authority has established 
instead of according to the dates in paragraphs (b)(1) through (4) of 
this section.
    (c) The compliance report must contain the information required in 
paragraphs (c)(1) through (4) of this section.
    (1) The information required by the summary report located in 
63.10(e)(3)(vi).
    (2) The total fuel use by each affected source subject to an 
emission limit, for each calendar month within the semiannual reporting 
period, including, but not limited to, a description of the fuel, 
whether the fuel has received a non-waste determination by EPA or your 
basis for concluding that the fuel is not a waste, and the total fuel 
usage amount with units of measure.
    (3) Indicate whether you burned new types of fuel during the 
reporting period. If you did burn new types of fuel you must include 
the date of the performance test where that fuel was in use.
    (4) Include the date of the most recent tune-up for each unit 
subject to the requirement to conduct a performance tune-up according 
to Sec.  63.10021(e). Include the date of the most recent burner 
inspection if it was not done annually and was delayed until the next 
scheduled unit shutdown.
    (d) For each excess emissions occurring at an affected source where 
you are using a CMS to comply with that emission limit or operating 
limit, you must include the information required in Sec.  
63.10(e)(3)(v) in the compliance report specified in section (c).
    (e) Each affected source that has obtained a Title V operating 
permit pursuant to part 70 or part 71 of this chapter must report all 
deviations as defined in this subpart in the semiannual monitoring 
report required by 40 CFR 70.6(a)(3)(iii)(A) or 40 CFR 
71.6(a)(3)(iii)(A). If an affected source submits a compliance report 
pursuant to Table 8 to this subpart along with, or as part of, the 
semiannual monitoring report required by 40 CFR 70.6(a)(3)(iii)(A) or 
40 CFR 71.6(a)(3)(iii)(A), and the compliance report includes all 
required information concerning deviations from any emission limit, 
operating limit, or work practice requirement in this subpart, 
submission of the compliance report satisfies any obligation to report 
the same deviations in the semiannual monitoring report. Submission of 
a compliance report does not otherwise affect any obligation the 
affected source may have to report deviations from permit requirements 
to the permit authority.
    (f) As of January 1, 2012, and within 60 days after the date of 
completing each performance test, you must submit the results of the 
performance tests required by this subpart to EPA's WebFIRE database by 
using the Compliance and Emissions Data Reporting Interface (CEDRI) 
that is accessed through EPA's Central Data Exchange (CDX) 
(www.epa.gov/cdx). Performance test data must be submitted in the file 
format generated through use of EPA's Electronic Reporting Tool (ERT) 
(see http://www.epa.gov/ttn/chief/ert/index.html). Only data collected 
using those test methods on the ERT Web site are subject to this 
requirement for submitting reports electronically to WebFIRE. Owners or 
operators who claim that some of the information being submitted for 
performance tests is confidential business information (CBI) must 
submit a complete ERT file including information claimed to be CBI on a 
compact disk or other commonly used electronic storage media 
(including, but not limited to, flash drives) to EPA. The electronic 
media must be clearly marked as CBI and mailed to U.S. EPA/OAPQS/CORE 
CBI Office, Attention: WebFIRE Administrator, MD C404-02, 4930 Old Page 
Rd., Durham, NC 27703. The same ERT file with the CBI omitted must be 
submitted to EPA via CDX as described earlier in this paragraph. At the 
discretion of the delegated authority, you must also submit these 
reports, including the confidential business information, to the 
delegated authority

[[Page 9483]]

in the format specified by the delegated authority.
    (1) Within 60 days after the date of completing each CEMS 
(SO2, PM, HCl, HF, and Hg) performance evaluation test, as 
defined in Sec.  63.2 and required by this subpart, you must submit the 
relative accuracy test audit (RATA) data (or, for PM CEMS, RCA and RRA 
data) required by this subpart to EPA's WebFIRE database by using the 
Compliance and Emissions Data Reporting Interface (CEDRI) that is 
accessed through EPA's Central Data Exchange (CDX) (www.epa.gov/cdx). 
The RATA data shall be submitted in the file format generated through 
use of EPA's Electronic Reporting Tool (ERT) (http://www.epa.gov/ttn/chief/ert/index.html). Only RATA data compounds listed on the ERT Web 
site are subject to this requirement. Owners or operators who claim 
that some of the information being submitted for RATAs is confidential 
business information (CBI) shall submit a complete ERT file including 
information claimed to be CBI on a compact disk or other commonly used 
electronic storage media (including, but not limited to, flash drives) 
by registered letter to EPA and the same ERT file with the CBI omitted 
to EPA via CDX as described earlier in this paragraph. The compact disk 
or other commonly used electronic storage media shall be clearly marked 
as CBI and mailed to U.S. EPA/OAPQS/CORE CBI Office, Attention: WebFIRE 
Administrator, MD C404-02, 4930 Old Page Rd., Durham, NC 27703. At the 
discretion of the delegated authority, owners or operators shall also 
submit these RATAs to the delegated authority in the format specified 
by the delegated authority. Owners or operators shall submit 
calibration error testing, drift checks, and other information required 
in the performance evaluation as described in Sec.  63.2 and as 
required in this chapter.
    (2) For a PM CEMS, PM CPMS, or approved alternative monitoring 
using a HAP metals CEMS, within 60 days after the reporting periods 
ending on March 31st, June 30th, September 30th, and December 31st, you 
must submit quarterly reports to EPA's WebFIRE database by using the 
Compliance and Emissions Data Reporting Interface (CEDRI) that is 
accessed through EPA's Central Data Exchange (CDX) (www.epa.gov/cdx). 
You must use the appropriate electronic reporting form in CEDRI or 
provide an alternate electronic file consistent with EPA's reporting 
form output format. For each reporting period, the quarterly reports 
must include all of the calculated 30-boiler operating day rolling 
average values derived from the CEMS and PM CPMS.
    (3) Reports for an SO2 CEMS, a Hg CEMS or sorbent trap 
monitoring system, an HCl or HF CEMS, and any supporting monitors for 
such systems (such as a diluent or moisture monitor) shall be submitted 
using the ECMPS Client Tool, as provided for in Appendices A and B to 
this subpart and Sec.  63.10021(f).
    (4) Submit the compliance reports required under paragraphs (c) and 
(d) of this section and the notification of compliance status required 
under Sec.  63.10030(e) to EPA's WebFIRE database by using the 
Compliance and Emissions Data Reporting Interface (CEDRI) that is 
accessed through EPA's Central Data Exchange (CDX) (www.epa.gov/cdx). 
You must use the appropriate electronic reporting form in CEDRI or 
provide an alternate electronic file consistent with EPA's reporting 
form output format.
    (5) All reports required by this subpart not subject to the 
requirements in paragraphs (f)(1) through (4) of this section must be 
sent to the Administrator at the appropriate address listed in Sec.  
63.13. If acceptable to both the Administrator and the owner or 
operator of a source, these reports may be submitted on electronic 
media. The Administrator retains the right to require submittal of 
reports subject to paragraphs (f)(1), (2), and (3) of this section in 
paper format.
    (g) If you had a malfunction during the reporting period, the 
compliance report must include the number, duration, and a brief 
description for each type of malfunction which occurred during the 
reporting period and which caused or may have caused any applicable 
emission limitation to be exceeded.


Sec.  63.10032  What records must I keep?

    (a) You must keep records according to paragraphs (a)(1) and (2) of 
this section. If you are required to (or elect to) continuously monitor 
Hg and/or HCl and/or HF emissions, you must also keep the records 
required under appendix A and/or appendix B to this subpart.
    (1) A copy of each notification and report that you submitted to 
comply with this subpart, including all documentation supporting any 
Initial Notification or Notification of Compliance Status or semiannual 
compliance report that you submitted, according to the requirements in 
Sec.  63.10(b)(2)(xiv).
    (2) Records of performance stack tests, fuel analyses, or other 
compliance demonstrations and performance evaluations, as required in 
Sec.  63.10(b)(2)(viii).
    (b) For each CEMS and CPMS, you must keep records according to 
paragraphs (b)(1) through (4) of this section.
    (1) Records described in Sec.  63.10(b)(2)(vi) through (xi).
    (2) Previous (i.e., superseded) versions of the performance 
evaluation plan as required in Sec.  63.8(d)(3).
    (3) Request for alternatives to relative accuracy test for CEMS as 
required in Sec.  63.8(f)(6)(i).
    (4) Records of the date and time that each deviation started and 
stopped, and whether the deviation occurred during a period of startup, 
shutdown, or malfunction or during another period.
    (c) You must keep the records required in Table 7 to this subpart 
including records of all monitoring data and calculated averages for 
applicable PM CPMS operating limits to show continuous compliance with 
each emission limit and operating limit that applies to you.
    (d) For each EGU subject to an emission limit, you must also keep 
the records in paragraphs (d)(1) through (3) of this section.
    (1) You must keep records of monthly fuel use by each EGU, 
including the type(s) of fuel and amount(s) used.
    (2) If you combust non-hazardous secondary materials that have been 
determined not to be solid waste pursuant to 40 CFR 241.3(b)(1), you 
must keep a record which documents how the secondary material meets 
each of the legitimacy criteria. If you combust a fuel that has been 
processed from a discarded non-hazardous secondary material pursuant to 
40 CFR 241.3(b)(2), you must keep records as to how the operations that 
produced the fuel satisfies the definition of processing in 40 CFR 
241.2. If the fuel received a non-waste determination pursuant to the 
petition process submitted under 40 CFR 241.3(c), you must keep a 
record which documents how the fuel satisfies the requirements of the 
petition process.
    (3) For an EGU that qualifies as an LEE under Sec.  63.10005(h), 
you must keep annual records that document that your emissions in the 
previous stack test(s) continue to qualify the unit for LEE status for 
an applicable pollutant, and document that there was no change in 
source operations including fuel composition and operation of air 
pollution control equipment that would cause emissions of the pollutant 
to increase within the past year.
    (e) If you elect to average emissions consistent with Sec.  
63.10009, you must additionally keep a copy of the emissions averaging 
implementation

[[Page 9484]]

plan required in Sec.  63.10009(g), all calculations required under 
Sec.  63.10009, including daily records of heat input or steam 
generation, as applicable, and monitoring records consistent with Sec.  
63.10022.
    (f) You must keep records of the occurrence and duration of each 
startup and/or shutdown.
    (g) You must keep records of the occurrence and duration of each 
malfunction of an operation (i.e., process equipment) or the air 
pollution control and monitoring equipment.
    (h) You must keep records of actions taken during periods of 
malfunction to minimize emissions in accordance with Sec.  63.10000(b), 
including corrective actions to restore malfunctioning process and air 
pollution control and monitoring equipment to its normal or usual 
manner of operation.
    (i) You must keep records of the type(s) and amount(s) of fuel used 
during each startup or shutdown.
    (j) If you elect to establish that an EGU qualifies as a limited-
use liquid oil-fired EGU, you must keep records of the type(s) and 
amount(s) of fuel use in each calendar quarter to document that the 
capacity factor limitation for that subcategory is met.


Sec.  63.10033  In what form and how long must I keep my records?

    (a) Your records must be in a form suitable and readily available 
for expeditious review, according to Sec.  63.10(b)(1).
    (b) As specified in Sec.  63.10(b)(1), you must keep each record 
for 5 years following the date of each occurrence, measurement, 
maintenance, corrective action, report, or record.
    (c) You must keep each record on site for at least 2 years after 
the date of each occurrence, measurement, maintenance, corrective 
action, report, or record, according to Sec.  63.10(b)(1). You can keep 
the records off site for the remaining 3 years.

Other Requirements and Information


Sec.  63.10040  What parts of the General Provisions apply to me?

    Table 9 to this subpart shows which parts of the General Provisions 
in Sec. Sec.  63.1 through 63.15 apply to you.


Sec.  63.10041  Who implements and enforces this subpart?

    (a) This subpart can be implemented and enforced by U.S. EPA, or a 
delegated authority such as your state, local, or tribal agency. If the 
EPA Administrator has delegated authority to your state, local, or 
tribal agency, then that agency (as well as the U.S. EPA) has the 
authority to implement and enforce this subpart. You should contact 
your EPA Regional Office to find out if this subpart is delegated to 
your state, local, or tribal agency.
    (b) In delegating implementation and enforcement authority of this 
subpart to a state, local, or tribal agency under 40 CFR part 63, 
subpart E, the authorities listed in paragraphs (b)(1) through (4) of 
this section are retained by the EPA Administrator and are not 
transferred to the state, local, or tribal agency; moreover, the U.S. 
EPA retains oversight of this subpart and can take enforcement actions, 
as appropriate, with respect to any failure by any person to comply 
with any provision of this subpart.
    (1) Approval of alternatives to the non-opacity emission limits and 
work practice standards in Sec.  63.9991(a) and (b) under Sec.  
63.6(g).
    (2) Approval of major change to test methods in Table 5 to this 
subpart under Sec.  63.7(e)(2)(ii) and (f) and as defined in Sec.  
63.90, approval of minor and intermediate changes to monitoring 
performance specifications/procedures in Table 5 where the monitoring 
serves as the performance test method (see definition of ``test 
method'' in Sec.  63.2.
    (3) Approval of major changes to monitoring under Sec.  63.8(f) and 
as defined in Sec.  63.90.
    (4) Approval of major change to recordkeeping and reporting under 
Sec.  63.10(e) and as defined in Sec.  63.90.


Sec.  63.10042  What definitions apply to this subpart?

    Terms used in this subpart are defined in the Clean Air Act (CAA), 
in Sec.  63.2 (the General Provisions), and in this section as follows:
    Affirmative defense means, in the context of an enforcement 
proceeding, a response or defense put forward by a defendant, regarding 
which the defendant has the burden of proof, and the merits of which 
are independently and objectively evaluated in a judicial or 
administrative proceeding.
    Anthracite coal means solid fossil fuel classified as anthracite 
coal by American Society of Testing and Materials (ASTM) Method D388-
05, ``Standard Classification of Coals by Rank'' (incorporated by 
reference, see Sec.  63.14).
    Bituminous coal means coal that is classified as bituminous 
according to ASTM Method D388-05, ``Standard Classification of Coals by 
Rank'' (incorporated by reference, see Sec.  63.14).
    Boiler operating day means a 24-hour period between midnight and 
the following midnight during which any fuel is combusted at any time 
in the steam generating unit. It is not necessary for the fuel to be 
combusted the entire 24-hour period.
    Capacity factor for a liquid oil-fired EGU means the total annual 
heat input from oil divided by the product of maximum hourly heat input 
for the EGU, regardless of fuel, multiplied by 8,760 hours.
    Coal means all solid fuels classifiable as anthracite, bituminous, 
sub-bituminous, or lignite by ASTM Method D388-05, ``Standard 
Classification of Coals by Rank'' (incorporated by reference, see Sec.  
63.14), and coal refuse. Synthetic fuels derived from coal for the 
purpose of creating useful heat including but not limited to, coal 
derived gases (not meeting the definition of natural gas), solvent-
refined coal, coal-oil mixtures, and coal-water mixtures, are 
considered ``coal'' for the purposes of this subpart.
    Coal-fired electric utility steam generating unit means an electric 
utility steam generating unit meeting the definition of ``fossil fuel-
fired'' that burns coal for more than 10.0 percent of the average 
annual heat input during any 3 consecutive calendar years or for more 
than 15.0 percent of the annual heat input during any one calendar 
year.
    Coal refuse means any by-product of coal mining, physical coal 
cleaning, and coal preparation operations (e.g., culm, gob, etc.) 
containing coal, matrix material, clay, and other organic and inorganic 
material with an ash content greater than 50 percent (by weight) and a 
heating value less than 13,900 kilojoules per kilogram (6,000 Btu per 
pound) on a dry basis.
    Cogeneration means a steam-generating unit that simultaneously 
produces both electrical and useful thermal (or mechanical) energy from 
the same primary energy source.
    Cogeneration unit means a stationary, fossil fuel-fired EGU meeting 
the definition of ``fossil fuel-fired'' or stationary, integrated 
gasification combined cycle:
    (1) Having equipment used to produce electricity and useful thermal 
energy for industrial, commercial, heating, or cooling purposes through 
the sequential use of energy; and
    (2) Producing during the 12-month period starting on the date the 
unit first produces electricity and during any calendar year after 
which the unit first produces electricity:
    (i) For a topping-cycle cogeneration unit,
    (A) Useful thermal energy not less than 5 percent of total energy 
output; and
    (B) Useful power that, when added to one-half of useful thermal 
energy produced, is not less than 42.5 percent

[[Page 9485]]

of total energy input, if useful thermal energy produced is 15 percent 
or more of total energy output, or not less than 45 percent of total 
energy input, if useful thermal energy produced is less than 15 percent 
of total energy output.
    (ii) For a bottoming-cycle cogeneration unit, useful power not less 
than 45 percent of total energy input.
    (3) Provided that the total energy input under paragraphs (2)(i)(B) 
and (2)(ii) of this definition shall equal the unit's total energy 
input from all fuel except biomass if the unit is a boiler.
    Combined-cycle gas stationary combustion turbine means a stationary 
combustion turbine system where heat from the turbine exhaust gases is 
recovered by a waste heat boiler.
    Common stack means the exhaust of emissions from two or more 
affected units through a single flue.
    Continental liquid oil-fired subcategory means any oil-fired 
electric utility steam generating unit that burns liquid oil and is 
located in the continental United States.
    Deviation. (1) Deviation means any instance in which an affected 
source subject to this subpart, or an owner or operator of such a 
source:
    (i) Fails to meet any requirement or obligation established by this 
subpart including, but not limited to, any emission limit, operating 
limit, work practice standard, or monitoring requirement; or
    (ii) Fails to meet any term or condition that is adopted to 
implement an applicable requirement in this subpart and that is 
included in the operating permit for any affected source required to 
obtain such a permit.
    (2) A deviation is not always a violation. The determination of 
whether a deviation constitutes a violation of the standard is up to 
the discretion of the entity responsible for enforcement of the 
standards.
    Distillate oil means fuel oils, including recycled oils, that 
comply with the specifications for fuel oil numbers 1 and 2, as defined 
by ASTM Method D396-10, ``Standard Specification for Fuel Oils'' 
(incorporated by reference, see Sec.  63.14).
    Dry flue gas desulfurization technology, or dry FGD, or spray dryer 
absorber (SDA), or spray dryer, or dry scrubber means an add-on air 
pollution control system located downstream of the steam generating 
unit that injects a dry alkaline sorbent (dry sorbent injection) or 
sprays an alkaline sorbent slurry (spray dryer) to react with and 
neutralize acid gases such as SO2 and HCl in the exhaust 
stream forming a dry powder material. Alkaline sorbent injection 
systems in fluidized bed combustors (FBC) or circulating fluidized bed 
(CFB) boilers are included in this definition.
    Dry sorbent injection (DSI) means an add-on air pollution control 
system in which sorbent (e.g., conventional activated carbon, 
brominated activated carbon, Trona, hydrated lime, sodium carbonate, 
etc.) is injected into the flue gas steam upstream of a PM control 
device to react with and neutralize acid gases (such as SO2 
and HCl) or Hg in the exhaust stream forming a dry powder material that 
may be removed in a primary or secondary PM control device.
    Electric Steam generating unit means any furnace, boiler, or other 
device used for combusting fuel for the purpose of producing steam 
(including fossil-fuel-fired steam generators associated with 
integrated gasification combined cycle gas turbines; nuclear steam 
generators are not included) for the purpose of powering a generator to 
produce electricity or electricity and other thermal energy.
    Electric utility steam generating unit (EGU) means a fossil fuel-
fired combustion unit of more than 25 megawatts electric (MWe) that 
serves a generator that produces electricity for sale. A fossil fuel-
fired unit that cogenerates steam and electricity and supplies more 
than one-third of its potential electric output capacity and more than 
25 MWe output to any utility power distribution system for sale is 
considered an electric utility steam generating unit.
    Emission limitation means any emissions limit, work practice 
standard, or operating limit.
    Excess emissions means, with respect to this subpart, results of 
any required measurements outside the applicable range (e.g., emissions 
limitations, parametric operating limits) that is permitted by this 
subpart. The values of measurements will be in the same units and 
averaging time as the values specified in this subpart for the 
limitations.
    Federally enforceable means all limitations and conditions that are 
enforceable by the Administrator, including the requirements of 40 CFR 
parts 60, 61, and 63; requirements within any applicable state 
implementation plan; and any permit requirements established under 40 
CFR 52.21 or under 40 CFR 51.18 and 40 CFR 51.24.
    Flue gas desulfurization system means any add-on air pollution 
control system located downstream of the steam generating unit whose 
purpose or effect is to remove at least 50 percent of the 
SO2 in the exhaust gas stream.
    Fossil fuel means natural gas, oil, coal, and any form of solid, 
liquid, or gaseous fuel derived from such material.
    Fossil fuel-fired means an electric utility steam generating unit 
(EGU) that is capable of combusting more than 25 MW of fossil fuels. To 
be ``capable of combusting'' fossil fuels, an EGU would need to have 
these fuels allowed in its operating permit and have the appropriate 
fuel handling facilities on-site or otherwise available (e.g., coal 
handling equipment, including coal storage area, belts and conveyers, 
pulverizers, etc.; oil storage facilities). In addition, fossil fuel-
fired means any EGU that fired fossil fuels for more than 10.0 percent 
of the average annual heat input during any 3 consecutive calendar 
years or for more than 15.0 percent of the annual heat input during any 
one calendar year after the applicable compliance date.
    Fuel type means each category of fuels that share a common name or 
classification. Examples include, but are not limited to, bituminous 
coal, subbituminous coal, lignite, anthracite, biomass, and residual 
oil. Individual fuel types received from different suppliers are not 
considered new fuel types.
    Fluidized bed boiler, or fluidized bed combustor, or circulating 
fluidized boiler, or CFB means a boiler utilizing a fluidized bed 
combustion process.
    Fluidized bed combustion means a process where a fuel is burned in 
a bed of granulated particles which are maintained in a mobile 
suspension by the upward flow of air and combustion products.
    Gaseous fuel includes, but is not limited to, natural gas, process 
gas, landfill gas, coal derived gas, solid oil-derived gas, refinery 
gas, and biogas.
    Generator means a device that produces electricity.
    Gross output means the gross useful work performed by the steam 
generated and, for an IGCC electric utility steam generating unit, the 
work performed by the stationary combustion turbines. For a unit 
generating only electricity, the gross useful work performed is the 
gross electrical output from the unit's turbine/generator sets. For a 
cogeneration unit, the gross useful work performed is the gross 
electrical output, including any such electricity used in the power 
production process (which process includes, but is not limited to, any 
on-site processing or treatment of fuel combusted at the unit and any 
on-site emission controls), or mechanical output plus 75 percent of the 
useful thermal output measured relative to ISO conditions that is not 
used to generate additional electrical or mechanical

[[Page 9486]]

output or to enhance the performance of the unit (i.e., steam delivered 
to an industrial process).
    Heat input means heat derived from combustion of fuel in an EGU 
(synthetic gas for an IGCC) and does not include the heat input from 
preheated combustion air, recirculated flue gases, or exhaust gases 
from other sources such as gas turbines, internal combustion engines, 
etc.
    Integrated gasification combined cycle electric utility steam 
generating unit or IGCC means an electric utility steam generating unit 
meeting the definition of ``fossil fuel-fired'' that burns a synthetic 
gas derived from coal and/or solid oil-derived fuel for more than 10.0 
percent of the average annual heat input during any 3 consecutive 
calendar years or for more than 15.0 percent of the annual heat input 
during any one calendar year in a combined-cycle gas turbine. No solid 
coal or solid oil-derived fuel is directly burned in the unit during 
operation.
    ISO conditions means a temperature of 288 Kelvin, a relative 
humidity of 60 percent, and a pressure of 101.3 kilopascals.
    Lignite coal means coal that is classified as lignite A or B 
according to ASTM Method D388-05, ``Standard Classification of Coals by 
Rank'' (incorporated by reference, see Sec.  63.14).
    Limited-use liquid oil-fired subcategory means an oil-fired 
electric utility steam generating unit with an annual capacity factor 
of less than 8 percent of its maximum or nameplate heat input, 
whichever is greater, averaged over a 24-month block contiguous period 
commencing April 16, 2015.
    Liquid fuel includes, but is not limited to, distillate oil and 
residual oil.
    Monitoring system malfunction or out of control period means any 
sudden, infrequent, not reasonably preventable failure of the 
monitoring system to provide valid data. Monitoring system failures 
that are caused in part by poor maintenance or careless operation are 
not malfunctions.
    Natural gas means a naturally occurring fluid mixture of 
hydrocarbons (e.g., methane, ethane, or propane) produced in geological 
formations beneath the Earth's surface that maintains a gaseous state 
at standard atmospheric temperature and pressure under ordinary 
conditions. Natural gas contains 20.0 grains or less of total sulfur 
per 100 standard cubic feet. Additionally, natural gas must either be 
composed of at least 70 percent methane by volume or have a gross 
calorific value between 950 and 1,100 Btu per standard cubic foot. 
Natural gas does not include the following gaseous fuels: landfill gas, 
digester gas, refinery gas, sour gas, blast furnace gas, coal-derived 
gas, producer gas, coke oven gas, or any gaseous fuel produced in a 
process which might result in highly variable sulfur content or heating 
value.
    Natural gas-fired electric utility steam generating unit means an 
electric utility steam generating unit meeting the definition of 
``fossil fuel-fired'' that is not a coal-fired, oil-fired, or IGCC 
electric utility steam generating unit and that burns natural gas for 
more than 10.0 percent of the average annual heat input during any 3 
consecutive calendar years or for more than 15.0 percent of the annual 
heat input during any one calendar year.
    Net-electric output means the gross electric sales to the utility 
power distribution system minus purchased power on a calendar year 
basis.
    Non-continental area means the State of Hawaii, the Virgin Islands, 
Guam, American Samoa, the Commonwealth of Puerto Rico, or the Northern 
Mariana Islands.
    Non-continental liquid oil-fired subcategory means any oil-fired 
electric utility steam generating unit that burns liquid oil and is 
located outside the continental United States.
    Non-mercury (Hg) HAP metals means Antimony (Sb), Arsenic (As), 
Beryllium (Be), Cadmium (Cd), Chromium (Cr), Cobalt (Co), Lead (Pb), 
Manganese (Mn), Nickel (Ni), and Selenium (Se). Oil means crude oil or 
petroleum or a fuel derived from crude oil or petroleum, including 
distillate and residual oil, solid oil-derived fuel (e.g., petroleum 
coke) and gases derived from solid oil-derived fuels (not meeting the 
definition of natural gas).
    Oil-fired electric utility steam generating unit means an electric 
utility steam generating unit meeting the definition of ``fossil fuel-
fired'' that is not a coal-fired electric utility steam generating unit 
and that burns oil for more than 10.0 percent of the average annual 
heat input during any 3 consecutive calendar years or for more than 
15.0 percent of the annual heat input during any one calendar year.
    Particulate matter or PM means any finely divided solid material as 
measured by the test methods specified under this subpart, or an 
alternative method.
    Pulverized coal (PC) boiler means an EGU in which pulverized coal 
is introduced into an air stream that carries the coal to the 
combustion chamber of the EGU where it is fired in suspension.
    Residual oil means crude oil, and all fuel oil numbers 4, 5 and 6, 
as defined by ASTM Method D396-10, ``Standard Specification for Fuel 
Oils'' (incorporated by reference, see Sec.  63.14).
    Responsible official means responsible official as defined in 40 
CFR 70.2.
    Shutdown means the cessation of operation of a boiler for any 
purpose. Shutdown begins either when none of the steam from the boiler 
is used to generate electricity for sale over the grid or for any other 
purpose (including on-site use), or at the point of no fuel being fired 
in the boiler, whichever is earlier. Shutdown ends when there is both 
no electricity being generated and no fuel being fired in the boiler.
    Startup means either the first-ever firing of fuel in a boiler for 
the purpose of producing electricity, or the firing of fuel in a boiler 
after a shutdown event for any purpose. Startup ends when any of the 
steam from the boiler is used to generate electricity for sale over the 
grid or for any other purpose (including on-site use).
    Stationary combustion turbine means all equipment, including but 
not limited to the turbine, the fuel, air, lubrication and exhaust gas 
systems, control systems (except emissions control equipment), and any 
ancillary components and sub-components comprising any simple cycle 
stationary combustion turbine, any regenerative/recuperative cycle 
stationary combustion turbine, the combustion turbine portion of any 
stationary cogeneration cycle combustion system, or the combustion 
turbine portion of any stationary combined cycle steam/electric 
generating system. Stationary means that the combustion turbine is not 
self propelled or intended to be propelled while performing its 
function. Stationary combustion turbines do not include turbines 
located at a research or laboratory facility, if research is conducted 
on the turbine itself and the turbine is not being used to power other 
applications at the research or laboratory facility.
    Steam generating unit means any furnace, boiler, or other device 
used for combusting fuel for the purpose of producing steam (including 
fossil-fuel-fired steam generators associated with integrated 
gasification combined cycle gas turbines; nuclear steam generators are 
not included).
    Stoker means a unit consisting of a mechanically operated fuel 
feeding mechanism, a stationary or moving grate to support the burning 
of fuel and admit undergrate air to the fuel, an overfire air system to 
complete combustion, and an ash discharge system. There are two general 
types of stokers: underfeed and

[[Page 9487]]

overfeed. Overfeed stokers include mass feed and spreader stokers.
    Subbituminous coal means coal that is classified as subbituminous 
A, B, or C according to ASTM Method D388-05, ``Standard Classification 
of Coals by Rank'' (incorporated by reference, see Sec.  63.14).
    Unit designed for coal  8,300 Btu/lb subcategory means 
any coal-fired EGU that is not a coal-fired EGU in the ``unit designed 
for low rank virgin coal'' subcategory.
    Unit designed for low rank virgin coal subcategory means any coal-
fired EGU that is designed to burn and that is burning nonagglomerating 
virgin coal having a calorific value (moist, mineral matter-free basis) 
of less than 19,305 kJ/kg (8,300 Btu/lb) that is constructed and 
operates at or near the mine that produces such coal.
    Unit designed to burn solid oil-derived fuel subcategory means any 
oil-fired EGU that burns solid oil-derived fuel.
    Voluntary consensus standards or VCS mean technical standards 
(e.g., materials specifications, test methods, sampling procedures, 
business practices) developed or adopted by one or more voluntary 
consensus bodies. The EPA/OAQPS has by precedent only used VCS that are 
written in English. Examples of VCS bodies are: American Society of 
Testing and Materials (ASTM), American Society of Mechanical Engineers 
(ASME), International Standards Organization (ISO), Standards Australia 
(AS), British Standards (BS), Canadian Standards (CSA), European 
Standard (EN or CEN) and German Engineering Standards (VDI). The types 
of standards that are not considered VCS are standards developed by: 
the U.S. states, e.g., California (CARB) and Texas (TCEQ); industry 
groups, such as American Petroleum Institute (API), Gas Processors 
Association (GPA), and Gas Research Institute (GRI); and other branches 
of the U.S. government, e.g., Department of Defense (DOD) and 
Department of Transportation (DOT). This does not preclude EPA from 
using standards developed by groups that are not VCS bodies within an 
EPA rule. When this occurs, EPA has done searches and reviews for VCS 
equivalent to these non-VCS methods.
    Wet flue gas desulfurization technology, or wet FGD, or wet 
scrubber means any add-on air pollution control device that is located 
downstream of the steam generating unit that mixes an aqueous stream or 
slurry with the exhaust gases from an EGU to control emissions of PM 
and/or to absorb and neutralize acid gases, such as SO2 and 
HCl.
    Work practice standard means any design, equipment, work practice, 
or operational standard, or combination thereof, which is promulgated 
pursuant to CAA section 112(h).

Tables to Subpart UUUUU of Part 63

                Table 1 to Subpart UUUUU of Part 63--Emission Limits for New or Reconstructed EGUs
          [As stated in Sec.   63.9991, you must comply with the following applicable emission limits]
----------------------------------------------------------------------------------------------------------------
                                                                                               Using these
                                                                                             requirements, as
                                                                   You must meet the        appropriate (e.g.,
                                                                   following emission       specified sampling
 If your EGU is in this subcategory .     For the following         limits and work         volume or test run
                 . .                       pollutants . . .      practice standards . .       duration) and
                                                                           .               limitations with the
                                                                                         test methods in Table .
                                                                                                   . .
----------------------------------------------------------------------------------------------------------------
1. Coal-fired unit not low rank        a. Filterable            7.0E-3 lb/MWh1.........  Collect a minimum of 4
 virgin coal.                           particulate matter                                dscm per run.
                                        (PM).
                                       OR                       OR                       .......................
                                       Total non-Hg HAP metals  6.0E-2 lb/GWh..........  Collect a minimum of 4
                                                                                          dscm per run.
                                       OR                       OR
                                       individual HAP metals:.                           Collect a minimum of 3
                                                                                          dscm per run.
                                       Antimony (Sb)..........  8.0E-3 lb/GW.
                                       Arsenic (As)...........  3.0E-3 lb/GWh.
                                       Beryllium (Be).........  6.0E-4 lb/GWh.
                                       Cadmium (Cd)...........  4.0E-4 lb/GWh.
                                       Chromium (Cr)..........  7.0E-3 lb/GWh.
                                       Cobalt (Co)............  2.0E-3 lb/GWh.
                                       Lead (Pb)..............  2.0E-3 lb/GWh.
                                       Manganese (Mn).........  4.0E-3 lb/GWh.
                                       Nickel (Ni)............  4.0E-2 lb/GWh.
                                       Selenium (Se)..........  6.0E-3 lb/GWh.
                                       b. Hydrogen chloride     4.0E-4 lb/MWh..........  For Method 26A, collect
                                        (HC1).                                            a minimum of 3 dscm
                                                                                          per run.
                                                                                         For ASTM D6348-03 2 or
                                                                                          Method 320, sample for
                                                                                          a minimum of 1 hour.
                                       OR.
                                       Sulfur dioxide (SO2) 3.  4.0E-1 lb/MWh..........  SO2 CEMS.
                                       c. Mercury (Hg)........  2.0E-4 lb/GWh..........  Hg CEMS or sorbent trap
                                                                                          monitoring system
                                                                                          only.
----------------------------------------------------------------------------------------------------------------
2. Coal-fired units low rank virgin    a. Filterable            7.0E-3 lb/MWh1.........  Collect a minimum of 4
 coal.                                  particulate matter                                dscm per run.
                                        (PM).
                                       OR                       OR                       .......................
                                       Total non-Hg HAP metals  6.0E-2 lb/GWh..........  Collect a minimum of 4
                                                                                          dscm per run.
                                       OR                       OR                       .......................
                                       Individual HAP metals:   .......................  Collect a minimum of 3
                                                                                          dscm per run.
                                       Antimony (Sb)..........  8.0E-3 lb/GWh.
                                       Arsenic (As)...........  3.0E-3 lb/GWh.

[[Page 9488]]

 
                                       Beryllium (Be).........  6.0E-4 lb/GWh.
                                       Cadmium (Cd)...........  4.0E-4 lb/GWh.
                                       Chromium (Cr)..........  7.0E-3 lb/GWh.
                                       Cobalt (Co)............  2.0E-3 lb/GWh.
                                       Lead (Pb)..............  2.0E-3 lb/GWh.
                                       Manganese (Mn).........  4.0E-3 lb/GWh.
                                       Nickel (Ni)............  4.0E-2 lb/GWh.
                                       Selenium (Se)..........  6.0E-3 lb/GWh.
                                       b. Hydrogen chloride     4.0E-4 lb/MWh..........  For Method 26A, collect
                                        (HCl).                                            a minimum of 3 dscm
                                                                                          per run.
                                                                                         For ASTM D6348-03 \2\
                                                                                          or Method 320, sample
                                                                                          for a minimum of 1
                                                                                          hour.
                                       OR                                                .......................
                                       Sulfur dioxide (SO2) 3.  4.0E-1 lb/MWh..........  SO2 CEMS.
                                       c. Mercury (Hg)........  4.0E-2 lb/GWh..........  Hg CEMS or sorbent trap
                                                                                          monitoring system
                                                                                          only.
----------------------------------------------------------------------------------------------------------------
3. IGCC unit.........................  a. Filterable            7.0E-2 lb/MWh 4........  Collect a minimum of 1
                                        particulate matter      9.0E-2 lb/MWh 5........   dscm per run.
                                        (PM).
                                       OR                       OR                       .......................
                                       Total non-Hg HAP metals  4.0E-1 lb/GWh..........  Collect a minimum of 1
                                                                                          dscm per run.
                                       OR                       OR                       .......................
                                       Individual HAP metals:   .......................  Collect a minimum of 2
                                                                                          dscm per run.
                                       Antimony (Sb)..........  2.0E-2 lb/GWh.
                                       Arsenic (As)...........  2.0E-2 lb/GWh.
                                       Beryllium (Be).........  1.0E-3 lb/GWh.
                                       Cadmium (Cd)...........  2.0E-3 lb/GWh.
                                       Chromium (Cr)..........  4.0E-2 lb/GWh.
                                       Cobalt (Co)............  4.0E-3 lb/GWh.
                                       Lead (Pb)..............  9.0E-3 lb/GWh.
                                       Manganese (Mn).........  2.0E-2 lb/GWh.
                                       Nickel (Ni)............  7.0E-2 lb/GWh.
                                       Selenium (Se)..........  3.0E-1 lb/GWh.
                                       b. Hydrogen chloride     2.0E-3 lb/MWh..........  For Method 26A, collect
                                        (HCl).                                            a minimum of 1 dscm
                                                                                          per run; for Method
                                                                                          26, collect a minimum
                                                                                          of 120 liters per run.
                                                                                         For ASTM D6348-03 \2\
                                                                                          or Method 320, sample
                                                                                          for a minimum of 1
                                                                                          hour.
                                       OR                                                .......................
                                       Sulfur dioxide (SO2) 3   4.0E-1 lb/MWh..........  SO2 CEMS.
                                       c. Mercury (Hg)........  3.0E-3 lb/GWh..........  Hg CEMS or sorbent trap
                                                                                          monitoring system
                                                                                          only.
----------------------------------------------------------------------------------------------------------------
4. Liquid oil-fired unit--continental  a. Filterable            7.0E-2 lb/MWh1.........  Collect a minimum of 1
 (excluding limited-use liquid oil-     particulate matter                                dscm per run.
 fired subcategory units).              (PM).
                                       OR                       OR                       .......................
                                       Total HAP metals.......  2.0E-4 lb/MWh..........  Collect a minimum of 2
                                                                                          dscm per run.
                                       OR                       OR                       .......................
                                       Individual HAP metals:   .......................  Collect a minimum of 2
                                                                                          dscm per run.
                                       Antimony (Sb)..........  1.0E-2 lb/GWh.
                                       Arsenic (As)...........  3.0E-3 lb/GWh.
                                       Beryllium (Be).........  5.0E-4 lb/GWh.
                                       Cadmium (Cd)...........  2.0E-4 lb/GWh.
                                       Chromium (Cr)..........  2.0E-2 lb/GWh.
                                       Cobalt (Co)............  3.0E-2 lb/GWh.
                                       Lead (Pb)..............  8.0E-3 lb/GWh.
                                       Manganese (Mn).........  2.0E-2 lb/GWh.
                                       Nickel (Ni)............  9.0E-2 lb/GWh.
                                       Selenium (Se)..........  2.0E-2 lb/GWh.

[[Page 9489]]

 
                                       Mercury (Hg)             1.0E-4 lb/GWh..........  For Method 30B sample
                                                                                          volume determination
                                                                                          (Section 8.2.4), the
                                                                                          estimated Hg
                                                                                          concentration should
                                                                                          nominally be <\1/2\
                                                                                          the standard.
                                       b. Hydrogen chloride     4.0E-4 lb/MWh..........  For Method 26A, collect
                                        (HCl)                                             a minimum of 3 dscm
                                                                                          per run.
                                                                                         For ASTM D6348-03 2 or
                                                                                          Method 320, sample for
                                                                                          a minimum of 1 hour.
                                       c. Hydrogen fluoride     4.0E-4 lb/MWh..........  For Method 26A, collect
                                        (HF)                                              a minimum of 3 dscm
                                                                                          per run.
                                                                                         For ASTM D6348-03 2 or
                                                                                          Method 320, sample for
                                                                                          a minimum of 1 hour.
----------------------------------------------------------------------------------------------------------------
5. Liquid oil-fired unit--non-         a. Filterable            2.0E-1 lb/MWh1.........  Collect a minimum of 1
 continental (excluding limited-use     particulate matter                                dscm per run.
 liquid oil-fired subcategory units).   (PM).
                                       OR                       OR                       .......................
                                       Total HAP metals         7.0E-3 lb/MWh..........  Collect a minimum of 1
                                                                                          dscm per run.
                                       OR                       OR                       .......................
                                       Individual HAP metals:   .......................  Collect a minimum of 3
                                                                                          dscm per run.
                                       Antimony (Sb)..........  8.0E-3 lb/GWh.
                                       Arsenic (As)...........  6.0E-2 lb/GWh.
                                       Beryllium (Be).........  2.0E-3 lb/GWh.
                                       Cadmium (Cd)...........  2.0E-3 lb/GWh.
                                       Chromium (Cr)..........  2.0E-2 lb/GWh.
                                       Cobalt (Co)............  3.0E-1 lb/GWh.
                                       Lead (Pb)..............  3.0E-2 lb/GWh.
                                       Manganese (Mn).........  1.0E-1 lb/GWh.
                                       Nickel (Ni)............  4.1E-0 lb/GWh.
                                       Selenium (Se)..........  2.0E-2 lb/GWh.
                                       Mercury (Hg)...........  4.0E-4 lb/GWh..........  For Method 30B sample
                                                                                          volume determination
                                                                                          (Section 8.2.4), the
                                                                                          estimated Hg
                                                                                          concentration should
                                                                                          nominally be < \1/2\
                                                                                          the standard.
                                       b. Hydrogen chloride     2.0E-3 lb/MWh..........  For Method 26A, collect
                                        (HCl)                                             a minimum of 1 dscm
                                                                                          per run; for Method
                                                                                          26, collect a minimum
                                                                                          of 120 liters per run.
                                                                                         For ASTM D6348-032 or
                                                                                          Method 320, sample for
                                                                                          a minimum of 1 hour
                                       c. Hydrogen fluoride     5.0E-4 lb/MWh..........  For Method 26A, collect
                                        (HF)                                              a minimum of 3 dscm
                                                                                          per run.
                                                                                         For ASTM D6348-03 2 or
                                                                                          Method 320, sample for
                                                                                          a minimum of 1 hour.
----------------------------------------------------------------------------------------------------------------
6. Solid oil-derived fuel-fired unit.  a. Filterable            2.0E-2 lb/MWh1.........  Collect a minimum of 1
                                        particulate matter                                dscm per run.
                                        (PM).
                                       OR                       OR                       .......................
                                       Total non-Hg HAP metals  6.0E-1 lb/GWh..........  Collect a minimum of 1
                                                                                          dscm per run.
                                       OR                       OR                       .......................
                                       Individual HAP metals:   .......................  Collect a minimum of 3
                                                                                          dscm per run.
                                       Antimony (Sb)..........  8.0E-3 lb/GWh.
                                       Arsenic (As)...........  3.0E-3 lb/GWh.
                                       Beryllium (Be).........  6.0E-4 lb/GWh.
                                       Cadmium (Cd)...........  7.0E-4 lb/GWh.
                                       Chromium (Cr)..........  6.0E-3 lb/GWh.
                                       Cobalt (Co)............  2.0E-3 lb/GWh.

[[Page 9490]]

 
                                       Lead (Pb)..............  2.0E-2 lb/GWh.
                                       Manganese (Mn).........  7.0E-3 lb/GWh.
                                       Nickel (Ni)............  4.0E-2 lb/GWh.
                                       Selenium (Se)..........  6.0E-3 lb/GWh.
                                       b. Hydrogen chloride     4.0E-4 lb/MWh..........  For Method 26A, collect
                                        (HCl).                                            a minimum of 3 dscm
                                                                                          per run.
                                                                                         For ASTM D6348-03 2 or
                                                                                          Method 320, sample for
                                                                                          a minimum of 1 hour.
                                       OR                                                .......................
 
                                       Sulfur dioxide (SO2) 3.  4.0E-1 lb/MWh..........  SO2 CEMS.
                                       c. Mercury (Hg)........  2.0E-3 lb/GWh..........  Hg CEMS or Sorbent trap
                                                                                          monitoring system
                                                                                          only.
----------------------------------------------------------------------------------------------------------------
1 Gross electric output.
2 Incorporated by reference, see Sec.   63.14.
3 You may not use the alternate SO2 limit if your EGU does not have some form of FGD system and SO2 CEMS
  installed.
4 Duct burners on syngas; gross electric output.
5 Duct burners on natural gas; gross electric output


                     Table 2 to Subpart UUUUU of Part 63--Emission Limits for Existing EGUs
        [As stated in Sec.   63.9991, you must comply with the following applicable emission limits] \1\
----------------------------------------------------------------------------------------------------------------
                                                                                               Using these
                                                                                             requirements, as
                                                                   You must meet the        appropriate (e.g.,
                                          For the following        following emission       specified sampling
  If your EGU is in this subcategory          pollutants            limits and work         volume or test run
                                                                   practice standards         duration) and
                                                                                           limitations with the
                                                                                         test methods in Table 5
----------------------------------------------------------------------------------------------------------------
1. Coal-fired unit not low rank        a. Filterable            3.0E-2 lb/MMBtu or 3.0E- Collect a minimum of 1
 virgin coal.                           particulate matter       1 lb/MWh \2\.            dscm per run.
                                        (PM).
                                       OR                       OR
                                       Total non-Hg HAP metals  5.0E-5 lb/MMBtu or 5.0E- Collect a minimum of 1
                                                                 1 lb/GWh.                dscm per run.
                                       OR                       OR
                                       Individual HAP metals
                                       Antimony (Sb)..........  8.0E-1 lb/TBtu or 8.0E-
                                                                 3 lb/GWh.
                                       Arsenic (As)...........  1.1E0 lb/TBtu or 2.0E-2
                                                                 lb/GWh.
                                       Beryllium (Be).........  2.0E-1 lb/TBtu or 2.0E-
                                                                 3 lb/GWh.
                                       Cadmium (Cd)...........  3.0E-1 lb/TBtu or 3.0E-
                                                                 3 lb/GWh.
                                       Chromium (Cr)..........  2.8E0 lb/TBtu or 3.0E-2
                                                                 lb/GWh.
                                       Cobalt (Co)............  8.0E-1 lb/TBtu or 8.0E-
                                                                 3 lb/GWh.
                                       Lead (Pb)..............  1.2E0 lb/TBtu or 2.0E-2
                                                                 lb/GWh.
                                       Manganese (Mn).........  4.0E0 lb/TBtu or 5.0E-2
                                                                 lb/GWh.
                                       Nickel (Ni)............  3.5E0 lb/TBtu or 4.0E-2
                                                                 lb/GWh.
                                       Selenium (Se)..........  5.0E0 lb/TBtu or 6.0E-2
                                                                 lb/GWh.
                                       b. Hydrogen chloride     2.0E-3 lb/MMBtu or 2.0E- For Method 26A, collect
                                        (HCl).                   2 lb/MWh.                a minimum of 0.75 dscm
                                                                                          per run; for Method
                                                                                          26, collect a minimum
                                                                                          of 120 liters per run.
                                                                                         For ASTM D6348-03 \3\
                                                                                          or Method 320, sample
                                                                                          for a minimum of 1
                                                                                          hour.
                                       OR
                                       Sulfur dioxide (SO2)     2.0E-1 lb/MMBtu or       SO2 CEMS.
                                        \4\.                     1.5E0 lb/MWh.
                                       c. Mercury (Hg)........  1.2E0 lb/TBtu or 1.3E-2  LEE Testing for 30 days
                                                                 lb/GWh.                  with 10 days maximum
                                                                                          per Method 30B run or
                                                                                          Hg CEMS or sorbent
                                                                                          trap monitoring system
                                                                                          only.
----------------------------------------------------------------------------------------------------------------
2. Coal-fired unit low rank virgin     a. Filterable            3.0E-2 lb/MMBtu or 3.0E- Collect a minimum of 1
 coal.                                  particulate matter       1 lb/MWh2.               dscm per run.
                                        (PM).
                                       OR                       OR
                                       Total non-Hg HAP metals  5.0E-5 lb/MMBtu or 5.0E- Collect a minimum of 1
                                                                 1 lb/GWh.                dscm per run.
                                       OR                       OR

[[Page 9491]]

 
                                       Individual HAP metals:   .......................  Collect a minimum of 3
                                                                                          dscm per run.
                                       Antimony (Sb)..........  8.0E-1 lb/TBtu or 8.0E-
                                                                 3 lb/GWh.
                                       Arsenic (As)...........  1.1E0 lb/TBtu or 2.0E-2
                                                                 lb/GWh.
                                       Beryllium (Be).........  2.0E-1 lb/TBtu or 2.0E-
                                                                 3 lb/GWh.
                                       Cadmium (Cd)...........  3.0E-1 lb/TBtu or 3.0E-
                                                                 3 lb/GWh.
                                       Chromium (Cr)..........  2.8E0 lb/TBtu or 3.0E-2
                                                                 lb/GWh.
                                       Cobalt (Co)............  8.0E-1 lb/TBtu or 8.0E-
                                                                 3 lb/GWh.
                                       Lead (Pb)..............  1.2E0 lb/TBtu or 2.0E-2
                                                                 lb/GWh.
                                       Manganese (Mn).........  4.0E0 lb/TBtu or 5.0E-2
                                                                 lb/GWh.
                                       Nickel (Ni)............  3.5E0 lb/TBtu or 4.0E-2
                                                                 lb/GWh.
                                       Selenium (Se)..........  5.0E0 lb/TBtu or 6.0E-2
                                                                 lb/GWh.
                                       b. Hydrogen chloride     2.0E-3 lb/MMBtu or 2.0E- For Method 26A, collect
                                        (HCl).                   2 lb/MWh.                a minimum of 0.75 dscm
                                                                                          per run; for Method
                                                                                          26, collect a minimum
                                                                                          of 120 liters per run.
                                                                                         For ASTM D6348-03 \3\
                                                                                          or Method 320, sample
                                                                                          for a minimum of 1
                                                                                          hour.
                                       OR
                                       Sulfur dioxide (SO2)     2.0E-1 lb/MMBtu or       SO2 CEMS.
                                        \4\.                     1.5E0 lb/MWh.
                                       c. Mercury (Hg)........  4.0E0 lb/TBtu or 4.0E-2  LEE Testing for 30 days
                                                                 lb/GWh.                  with 10 days maximum
                                                                                          per Method 30B run or
                                                                                          Hg CEMS or sorbent
                                                                                          trap monitoring system
                                                                                          only.
----------------------------------------------------------------------------------------------------------------
3. IGCC unit.........................  a. Filterable            4.0E-2 lb/MMBtu or 4.0E- Collect a minimum of 1
                                        particulate matter       1 lb/MWh2.               dscm per run.
                                        (PM).
                                       OR                       OR
                                       Total non-Hg HAP metals  6.0E-5 lb/MMBtu or 5.0E- Collect a minimum of 1
                                                                 1 lb/GWh.                dscm per run.
                                       OR                       OR
                                       Individual HAP metals:.  .......................  Collect a minimum of 2
                                                                                          dscm per run.
                                       Antimony (Sb)..........  1.4E0 lb/TBtu or 2.0E-2
                                                                 lb/GWh.
                                       Arsenic (As)...........  1.5E0 lb/TBtu or 2.0E-2
                                                                 lb/GWh.
                                       Beryllium (Be).........  1.0E-1 lb/TBtu or 1.0E-
                                                                 3 lb/GWh.
                                       Cadmium (Cd)...........  1.5E-1 lb/TBtu or 2.0E-
                                                                 3 lb/GWh.
                                       Chromium (Cr)..........  2.9E0 lb/TBtu or 3.0E-2
                                                                 lb/GWh.
                                       Cobalt (Co)............  1.2E0 lb/TBtu or 2.0E-2
                                                                 lb/GWh.
                                       Lead (Pb)..............  1.9E+2 lb/MMBtu or
                                                                 1.8E0 lb/MWh.
                                       Manganese (Mn).........  2.5E0 lb/TBtu or 3.0E-2
                                                                 lb/GWh.
                                       Nickel (Ni)............  6.5E0 lb/TBtu or 7.0E-2
                                                                 lb/GWh.
                                       Selenium (Se)..........  2.2E+1 lb/TBtu or 3.0E-
                                                                 1 lb/GWh.
                                       b. Hydrogen chloride     5.0E-4 lb/MMBtu or 5.0E- For Method 26A, collect
                                        (HCl).                   3 lb/MWh.                a minimum of 1 dscm
                                                                                          per
                                                                                         run; for Method 26,
                                                                                          collect a minimum of
                                                                                          120 liters per run.
                                                                                         For ASTM D6348-03 \3\
                                                                                          or Method 320, sample
                                                                                          for a minimum of 1
                                                                                          hour.
                                       c. Mercury (Hg)........  2.5E0 lb/TBtu or 3.0E-2  LEE Testing for 30 days
                                                                 lb/GWh.                  with 10 days maximum
                                                                                          per Method 30B run or
                                                                                          Hg CEMS or sorbent
                                                                                          trap monitoring system
                                                                                          only.
----------------------------------------------------------------------------------------------------------------
4. Liquid oil-fired unit--continental  a. Filterable            3.0E-2 lb/MMBtu or 3.0E- Collect a minimum of 1
 (excluding limited-use liquid oil-     particulate matter       1 lb/MWh2.               dscm per run.
 fired subcategory units).              (PM).
                                       OR                       OR
                                       Total HAP metals.......  8.0E-4 lb/MMBtu or 8.0E- Collect a minimum of 1
                                                                 3 lb/MWh.                dscm per run.
                                       OR                       OR
                                       Individual HAP metals..                           Collect a minimum of 1
                                                                                          dscm per run.

[[Page 9492]]

 
                                       Antimony (Sb)..........  1.3E+1 lb/TBtu or 2.0E-
                                                                 1 lb/GWh.
                                       Arsenic (As)...........  2.8E0 lb/TBtu or 3.0E-2
                                                                 lb/GWh.
                                       Beryllium (Be).........  2.0E-1 lb/TBtu or 2.0E-
                                                                 3 lb/GWh.
                                       Cadmium (Cd)...........  3.0E-1 lb/TBtu or 2.0E-
                                                                 3 lb/GWh.
                                       Chromium (Cr)..........  5.5E0 lb/TBtu or 6.0E-2
                                                                 lb/GWh.
                                       Cobalt (Co)............  2.1E+1 lb/TBtu or 3.0E-
                                                                 1 lb/GWh.
                                       Lead (Pb)..............  8.1E0 lb/TBtu or 8.0E-2
                                                                 lb/GWh.
                                       Manganese (Mn).........  2.2E+1 lb/TBtu or 3.0E-
                                                                 1 lb/GWh.
                                       Nickel (Ni)............  1.1E+2 lb/TBtu or 1.1E0
                                                                 lb/GWh.
                                       Selenium (Se)..........  3.3E0 lb/TBtu or 4.0E-2
                                                                 lb/GWh.
                                       Mercury (Hg)...........  2.0E-1 lb/TBtu or 2.0E-  For Method 30B sample
                                                                 3 lb/GWh.                volume determination
                                                                                          (Section 8.2.4), the
                                                                                          estimated Hg
                                                                                          concentration should
                                                                                          nominally be < \1/2\
                                                                                          the standard.
                                       b. Hydrogen chloride     2.0E-3 lb/MMBtu or 1.0E- For Method 26A, collect
                                        (HCl).                   2 lb/MWh.                a minimum of 1 dscm
                                                                                          per
                                                                                         Run; for Method 26,
                                                                                          collect a minimum of
                                                                                          120 liters per run.
                                                                                         For ASTM D6348-03 \3\
                                                                                          or Method 320, sample
                                                                                          for a minimum of 1
                                                                                          hour.
                                       c. Hydrogen fluoride     4.0E-4 lb/MMBtu or 4.0E- For Method 26A, collect
                                        (HF).                    3 lb/MWh.                a minimum of 1 dscm
                                                                                          per run; for Method
                                                                                          26, collect a minimum
                                                                                          of 120 liters per run.
                                                                                         For ASTM D6348-03 \3\
                                                                                          or Method 320, sample
                                                                                          for a minimum of 1
                                                                                          hour.
----------------------------------------------------------------------------------------------------------------
5. Liquid oil-fired unit--non-         a. Filterable            3.0E-2 lb/MMBtu or 3.0E- Collect a minimum of 1
 continental (excluding limited-use     particulate matter       1 lb/MWh2.               dscm per run.
 liquid oil-fired subcategory units).   (PM).
                                       OR                       OR
                                       Total HAP metals.......  6.0E-4 lb/MMBtu or 7.0E- Collect a minimum of 1
                                                                 3 lb/MWh.                dscm per run.
                                       OR                       OR
                                       Individual HAP metals..  .......................  Collect a minimum of 2
                                                                                          dscm per run.
                                       Antimony (Sb)..........  2.2E0 lb/TBtu or 2.0E-2
                                                                 lb/GWh.
                                       Arsenic (As)...........  4.3E0 lb/TBtu or 8.0E-2
                                                                 lb/GWh.
                                       Beryllium (Be).........  6.0E-1 lb/TBtu or 3.0E-
                                                                 3 lb/GWh.
                                       Cadmium (Cd)...........  3.0E-1 lb/TBtu or 3.0E-
                                                                 3 lb/GWh.
                                       Chromium (Cr)..........  3.1E+1 lb/TBtu or 3.0E-
                                                                 1 lb/GWh.
                                       Cobalt (Co)............  1.1E+2 lb/TBtu or 1.4E0
                                                                 lb/GWh.
                                       Lead (Pb)..............  4.9E0 lb/TBtu or 8.0E-2
                                                                 lb/GWh.
                                       Manganese (Mn).........  2.0E+1 lb/TBtu or 3.0E-
                                                                 1 lb/GWh.
                                       Nickel (Ni)............  4.7E+2 lb/TBtu or 4.1E0
                                                                 lb/GWh.
                                       Selenium (Se)..........  9.8E0 lb/TBtu or 2.0E-1
                                                                 lb/GWh.
                                       Mercury (Hg)...........  4.0E-2 lb/TBtu or 4.0E-  For Method 30B sample
                                                                 4 lb/GWh.                volume determination
                                                                                          (Section 8.2.4), the
                                                                                          estimated Hg
                                                                                          concentration should
                                                                                          nominally be < \1/2\
                                                                                          the standard.
                                       Hydrogen chloride (HCl)  2.0E-4 lb/MMBtu or 2.0E- For Method 26A, collect
                                                                 3 lb/MWh.                a minimum of 1 dscm
                                                                                          per run; for Method
                                                                                          26, collect a minimum
                                                                                          of 120 liters per run.
                                                                                         For ASTM D6348-03 \3\
                                                                                          or Method 320, sample
                                                                                          for a minimum of 2
                                                                                          hours.
                                       c. Hydrogen fluoride     6.0E-5 lb/MMBtu or 5.0E- For Method 26A, collect
                                        (HF).                    4 lb/MWh.                a minimum of 3 dscm
                                                                                          per run.
                                                                                         For ASTM D6348-03 \3\
                                                                                          or Method 320, sample
                                                                                          for a minimum of 2
                                                                                          hours.
----------------------------------------------------------------------------------------------------------------

[[Page 9493]]

 
6. Solid oil-derived fuel-fired unit.  a. Filterable            8.0E-3 lb/MMBtu or 9.0E- Collect a minimum of 1
                                        particulate matter       2 lb/MWh2.               dscm per run.
                                        (PM).
                                       OR                       OR
                                       Total non-Hg HAP metals  4.0E-5 lb/MMBtu or 6.0E- Collect a minimum of 1
                                                                 1 lb/GWh.                dscm per run.
                                       OR                       OR
                                       Individual HAP metals..  .......................  Collect a minimum of 3
                                                                                          dscm per run.
                                       Antimony (Sb)..........  8.0E-1 lb/TBtu or 8.0E-
                                                                 3 lb/GWh.
                                       Arsenic (As)...........  3.0E-1 lb/TBtu or 5.0E-
                                                                 3 lb/GWh.
                                       Beryllium (Be).........  6.0E-2 lb/TBtu or 6.0E-
                                                                 4 lb/GWh.
                                       Cadmium (Cd)...........  3.0E-1 lb/TBtu or 4.0E-
                                                                 3 lb/GWh.
                                       Chromium (Cr)..........  8.0E-1 lb/TBtu or 2.0E-
                                                                 2 lb/GWh.
                                       Cobalt (Co)............  1.1E0 lb/TBtu or 2.0E-2
                                                                 lb/GWh.
                                       Lead (Pb)..............  8.0E-1 lb/TBtu or 2.0E-
                                                                 2 lb/GWh.
                                       Manganese (Mn).........  2.3E0 lb/TBtu or 4.0E-2
                                                                 lb/GWh.
                                       Nickel (Ni)............  9.0E0 lb/TBtu or 2.0E-1
                                                                 lb/GWh.
                                       Selenium (Se)..........  1.2E0 lb/TBtu 2.0E-2 lb/
                                                                 GWh.
                                       b. Hydrogen chloride     5.0E-3 lb/MMBtu or 8.0E- For Method 26A, collect
                                        (HCl).                   2 lb/MWh.                a minimum of 0.75 dscm
                                                                                          per run; for Method
                                                                                          26, collect a minimum
                                                                                          of 120 liters per run.
                                                                                         For ASTM D6348-03 \3\
                                                                                          or Method 320, sample
                                                                                          for a minimum of 1
                                                                                          hour.
                                       OR
                                       Sulfur dioxide (SO2)     3.0E-1 lb/MMBtu or       SO2 CEMS.
                                        \4\.                     2.0E0 lb/MWh.
                                       c. Mercury (Hg)........  2.0E-1 lb/TBtu or 2.0E-  LEE Testing for 30 days
                                                                 3 lb/GWh.                with 10 days maximum
                                                                                          per Method 30B run or
                                                                                          Hg CEMS or Sorbent
                                                                                          trap monitoring system
                                                                                          only.
----------------------------------------------------------------------------------------------------------------
\1\ For LEE emissions testing for total PM, total HAP metals, individual HAP metals, HCl, and HF, the required
  minimum sampling volume must be increased nominally by a factor of two.
\2\ Gross electric output.
\3\ Incorporated by reference, see Sec.   63.14.
\4\ You may not use the alternate SO2 limit if your EGU does not have some form of FGD system and SO2 CEMS
  installed.


      Table 3 to Subpart UUUUU of Part 63--Work Practice Standards
 [As stated in Sec.  Sec.   63.9991, you must comply with the following
                   applicable work practice standards]
------------------------------------------------------------------------
     If your EGU is . . .          You must meet the following . . .
------------------------------------------------------------------------
1. An existing EGU...........  Conduct a tune-up of the EGU burner and
                                combustion controls at least each 36
                                calendar months, or each 48 calendar
                                months if neural network combustion
                                optimization software is employed, as
                                specified in Sec.   63.10021(e).
------------------------------------------------------------------------
2. A new or reconstructed EGU  Conduct a tune-up of the EGU burner and
                                combustion controls at least each 36
                                calendar months, or each 48 calendar
                                months if neural network combustion
                                optimization software is employed, as
                                specified in Sec.   63.10021(e).
------------------------------------------------------------------------
3. A coal-fired, liquid oil-   You must operate all CMS during startup.
 fired, or solid oil-derived    Startup means either the first-ever
 fuel-fired EGU during          firing of fuel in a boiler for the
 startup.                       purpose of producing electricity, or the
                                firing of fuel in a boiler after a
                                shutdown event for any purpose. Startup
                                ends when any of the steam from the
                                boiler is used to generate electricity
                                for sale over the grid or for any other
                                purpose (including on site use). For
                                startup of a unit, you must use clean
                                fuels, either natural gas or distillate
                                oil or a combination of clean fuels for
                                ignition. Once you convert to firing
                                coal, residual oil, or solid oil-derived
                                fuel, you must engage all of the
                                applicable control technologies except
                                dry scrubber and SCR. You must start
                                your dry scrubber and SCR systems, if
                                present, appropriately to comply with
                                relevant standards applicable during
                                normal operation. You must comply with
                                all applicable emissions limits at all
                                times except for periods that meet the
                                definitions of startup and shutdown in
                                this subpart. You must keep records
                                during periods of startup. You must
                                provide reports concerning activities
                                and periods of startup, as specified in
                                Sec.   63.10011(g) and Sec.
                                63.10021(h) and (i).
------------------------------------------------------------------------

[[Page 9494]]

 
4. A coal-fired, liquid oil-   You must operate all CMS during shutdown.
 fired, or solid oil-derived    Shutdown means the cessation of
 fuel-fired EGU during          operation of a boiler for any purpose.
 shutdown.                      Shutdown begins either when none of the
                                steam from the boiler is used to
                                generate electricity for sale over the
                                grid or for any other purpose (including
                                on-site use) or at the point of no fuel
                                being fired in the boiler. Shutdown ends
                                when there is both no electricity being
                                generated and no fuel being fired in the
                                boiler. During shutdown, you must
                                operate all applicable control
                                technologies while firing coal, residual
                                oil, or solid oil-derived fuel. You must
                                comply with all applicable emissions
                                limits at all times except for periods
                                that meet the definitions of startup and
                                shutdown in this subpart. You must keep
                                records during periods of startup. You
                                must provide reports concerning
                                activities and periods of startup, as
                                specified in Sec.   63.10011(g) and Sec.
                                  63.10021(h) and (i).
------------------------------------------------------------------------


     Table 4 to Subpart UUUUU of Part 63--Operating Limits for EGUs
    [As stated in Sec.   63.9991, you must comply with the applicable
                            operating limits]
------------------------------------------------------------------------
If you demonstrate compliance   You must meet these operating limits . .
         using . . .                               .
------------------------------------------------------------------------
1. PM CPMS...................  Maintain the 30-boiler operating day
                                rolling average PM CPMS output at or
                                below the highest 1-hour average
                                measured during the most recent
                                performance test demonstrating
                                compliance with the filterable PM, total
                                non-mercury HAP metals (total HAP
                                metals, for liquid oil-fired units), or
                                individual non-mercury HAP metals
                                (individual HAP metals including Hg, for
                                liquid oil-fired units) emissions
                                limitation(s).
------------------------------------------------------------------------


                      Table 5 to Subpart UUUUU of Part 63--Performance Testing Requirements
   [As stated in Sec.   63.10007, you must comply with the following requirements for performance testing for
                              existing, new or reconstructed affected sources \1\]
----------------------------------------------------------------------------------------------------------------
                                                              You must perform the
                                                            following activities, as
 To conduct a performance test for       Using . . .        applicable to your input-       Using \2\ . . .
   the following pollutant . . .                            or output-based emission
                                                                   limit . . .
----------------------------------------------------------------------------------------------------------------
1. Filterable Particulate matter    Emissions Testing....  a. Select sampling ports    Method 1 at Appendix A-1
 (PM).                                                      location and the number     to part 60 of this
                                                            of traverse points.         chapter.
                                                           b. Determine velocity and   Method 2, 2A, 2C, 2F, 2G
                                                            volumetric flow-rate of     or 2H at Appendix A-1 or
                                                            the stack gas.              A-2 to part 60 of this
                                                                                        chapter.
                                                           c. Determine oxygen and     Method 3A or 3B at
                                                            carbon dioxide              Appendix A-2 to part 60
                                                            concentrations of the       of this chapter, or ANSI/
                                                            stack gas.                  ASME PTC 19.10-1981.\3\
                                                           d. Measure the moisture     Method 4 at Appendix A-3
                                                            content of the stack gas.   to part 60 of this
                                                                                        chapter.
                                                           e. Measure the filterable   Method 5 at Appendix A-3
                                                            PM concentration.           to part 60 of this
                                                                                        chapter.
                                                                                       For positive pressure
                                                                                        fabric filters, Method
                                                                                        5D at Appendix A-3 to
                                                                                        part 60 of this chapter
                                                                                        for filterable PM
                                                                                        emissions.
                                                                                       Note that the Method 5
                                                                                        front half temperature
                                                                                        shall be 160 [deg]  14 [deg]C (320
                                                                                        [deg]  25
                                                                                        [deg]F).
                                                           f. Convert emissions        Method 19 F-factor
                                                            concentration to lb/MMBtu   methodology at Appendix
                                                            or lb/MWh emissions rates.  A-7 to part 60 of this
                                                                                        chapter, or calculate
                                                                                        using mass emissions
                                                                                        rate and electrical
                                                                                        output data (see Sec.
                                                                                        63.10007(e)).
                                    OR                     OR
                                    PM CEMS                a. Install, certify,        Performance Specification
                                                            operate, and maintain the   11 at Appendix B to part
                                                            PM CEMS.                    60 of this chapter and
                                                                                        Procedure 2 at Appendix
                                                                                        F to Part 60 of this
                                                                                        chapter.
                                                           b. Install, certify,        Part 75 of this chapter
                                                            operate, and maintain the   and Sec.  Sec.
                                                            diluent gas, flow rate,     63.10010(a), (b), (c),
                                                            and/or moisture             and (d).
                                                            monitoring systems.
                                                           c. Convert hourly           Method 19 F-factor
                                                            emissions concentrations    methodology at Appendix
                                                            to 30 boiler operating      A-7 to part 60 of this
                                                            day rolling average lb/     chapter, or calculate
                                                            MMBtu or lb/MWh emissions   using mass emissions
                                                            rates.                      rate and electrical
                                                                                        output data (see Sec.
                                                                                        63.10007(e)).
----------------------------------------------------------------------------------------------------------------
2. Total or individual non-Hg HAP   Emissions Testing....  a. Select sampling ports    Method 1 at Appendix A-1
 metals.                                                    location and the number     to part 60 of this
                                                            of traverse points.         chapter.
                                                           b. Determine velocity and   Method 2, 2A, 2C, 2F, 2G
                                                            volumetric flow-rate of     or 2H at Appendix A-1 or
                                                            the stack gas.              A-2 to part 60 of this
                                                                                        chapter.

[[Page 9495]]

 
                                                           c. Determine oxygen and     Method 3A or 3B at
                                                            carbon dioxide              Appendix A-2 to part 60
                                                            concentrations of the       of this chapter, or ANSI/
                                                            stack gas.                  ASME PTC 19.10-1981.\3\
                                                           d. Measure the moisture     Method 4 at Appendix A-3
                                                            content of the stack gas.   to part 60 of this
                                                                                        chapter.
                                                           e. Measure the HAP metals   Method 29 at Appendix A-8
                                                            emissions concentrations    to part 60 of this
                                                            and determine each          chapter. For liquid oil-
                                                            individual HAP metals       fired units, Hg is
                                                            emissions concentration,    included in HAP metals
                                                            as well as the total        and you may use Method
                                                            filterable HAP metals       29, Method 30B at
                                                            emissions concentration     Appendix A-8 to part 60
                                                            and total HAP metals        of this chapter; for
                                                            emissions concentration.    Method 29, you must
                                                                                        report the front half
                                                                                        and back half results
                                                                                        separately.
                                                           f. Convert emissions        Method 19 F-factor
                                                            concentrations              methodology at Appendix
                                                            (individual HAP metals,     A-7 to part 60 of this
                                                            total filterable HAP        chapter, or calculate
                                                            metals, and total HAP       using mass emissions
                                                            metals) to lb/MMBtu or lb/  rate and electrical
                                                            MWh emissions rates.        output data (see Sec.
                                                                                        63.10007(e)).
----------------------------------------------------------------------------------------------------------------
3. Hydrogen chloride (HCl) and      Emissions Testing....  a. Select sampling ports    Method 1 at Appendix A-1
 hydrogen fluoride (HF).                                    location and the number     to part 60 of this
                                                            of traverse points.         chapter.
                                                           b. Determine velocity and   Method 2, 2A, 2C, 2F, 2G
                                                            volumetric flow-rate of     or 2H at Appendix A-1 or
                                                            the stack gas.              A-2 to part 60 of this
                                                                                        chapter.
                                                           c. Determine oxygen and     Method 3A or 3B at
                                                            carbon dioxide              Appendix A-2 to part 60
                                                            concentrations of the       of this chapter, or ANSI/
                                                            stack gas.                  ASME PTC 19.10-1981.\3\
                                                           d. Measure the moisture     Method 4 at Appendix A-3
                                                            content of the stack gas.   to part 60 of this
                                                                                        chapter.
                                                           e. Measure the HCl and HF   Method 26 or Method 26A
                                                            emissions concentrations.   at Appendix A-8 to part
                                                                                        60 of this chapter or
                                                                                        Method 320 at Appendix A
                                                                                        to part 63 of this
                                                                                        chapter or ASTM 6348-03
                                                                                        \3\ with (1) additional
                                                                                        quality assurance
                                                                                        measures in footnote \4\
                                                                                        and (2) spiking levels
                                                                                        nominally no greater
                                                                                        than two times the level
                                                                                        corresponding to the
                                                                                        applicable emission
                                                                                        limit. Method 26A must
                                                                                        be used if there are
                                                                                        entrained water droplets
                                                                                        in the exhaust stream.
                                                           f. Convert emissions        Method 19 F-factor
                                                            concentration to lb/MMBtu   methodology at Appendix
                                                            or lb/MWh emissions rates.  A-7 to part 60 of this
                                                                                        chapter, or calculate
                                                                                        using mass emissions
                                                                                        rate and electrical
                                                                                        output data (see Sec.
                                                                                        63.10007(e)).
                                    OR                     OR
                                    HCl and/or HF CEMS...  a. Install, certify,        Appendix B of this
                                                            operate, and maintain the   subpart.
                                                            HCl or HF CEMS.
                                                           b. Install, certify,        Part 75 of this chapter
                                                            operate, and maintain the   and Sec.  Sec.
                                                            diluent gas, flow rate,     63.10010(a), (b), (c),
                                                            and/or moisture             and (d).
                                                            monitoring systems.
                                                           c. Convert hourly           Method 19 F-factor
                                                            emissions concentrations    methodology at Appendix
                                                            to 30 boiler operating      A-7 to part 60 of this
                                                            day rolling average lb/     chapter, or calculate
                                                            MMBtu or lb/MWh emissions   using mass emissions
                                                            rates.                      rate and electrical
                                                                                        output data (see Sec.
                                                                                        63.10007(e)).
----------------------------------------------------------------------------------------------------------------
4. Mercury (Hg)...................  Emissions Testing....  a. Select sampling ports    Method 1 at Appendix A-1
                                                            location and the number     to part 60 of this
                                                            of traverse points.         chapter or Method 30B at
                                                                                        Appendix A-8 for Method
                                                                                        30B point selection.
                                                           b. Determine velocity and   Method 2, 2A, 2C, 2F, 2G
                                                            volumetric flow-rate of     or 2H at Appendix A-1 or
                                                            the stack gas.              A-2 to part 60 of this
                                                                                        chapter.
                                                           c. Determine oxygen and     Method 3A or 3B at
                                                            carbon dioxide              Appendix A-1 to part 60
                                                            concentrations of the       of this chapter, or ANSI/
                                                            stack gas.                  ASME PTC 19.10-1981.\3\
                                                           d. Measure the moisture     Method 4 at Appendix A-3
                                                            content of the stack gas.   to part 60 of this
                                                                                        chapter.
                                                           e. Measure the Hg emission  Method 30B at Appendix A-
                                                            concentration.              8 to part 60 of this
                                                                                        chapter, ASTM D6784 \3\,
                                                                                        or Method 29 at Appendix
                                                                                        A-8 to part 60 of this
                                                                                        chapter; for Method 29,
                                                                                        you must report the
                                                                                        front half and back half
                                                                                        results separately.

[[Page 9496]]

 
                                                           f. Convert emissions        Method 19 F-factor
                                                            concentration to lb/TBtu    methodology at Appendix
                                                            or lb/GWh emission rates.   A-7 to part 60 of this
                                                                                        chapter, or calculate
                                                                                        using mass emissions
                                                                                        rate and electrical
                                                                                        output data (see Sec.
                                                                                        63.10007(e)).
                                    OR                     OR
                                                           Hg CEMS...................  Sections 3.2.1 and 5.1 of
                                                           a. Install, certify,         Appendix A of this
                                                            operate, and maintain the   subpart.
                                                            CEMS.
                                                           b. Install, certify,        Part 75 of this chapter
                                                            operate, and maintain the   and Sec.  Sec.
                                                            diluent gas, flow rate,     63.10010(a), (b), (c),
                                                            and/or moisture             and (d).
                                                            monitoring systems.
                                                           c. Convert hourly           Section 6 of Appendix A
                                                            emissions concentrations    to this subpart.
                                                            to 30 boiler operating
                                                            day rolling average lb/
                                                            TBtu or lb/GWh emissions
                                                            rates.
                                    OR                     OR
                                    Sorbent trap           a. Install, certify,        Sections 3.2.2 and 5.2 of
                                     monitoring system.     operate, and maintain the   Appendix A to this
                                                            sorbent trap monitoring     subpart.
                                                            system.
                                                           b. Install, operate, and    Part 75 of this chapter
                                                            maintain the diluent gas,   and Sec.  Sec.
                                                            flow rate, and/or           63.10010(a), (b), (c),
                                                            moisture monitoring         and (d).
                                                            systems.
                                                           c. Convert emissions        Section 6 of Appendix A
                                                            concentrations to 30        to this subpart.
                                                            boiler operating day
                                                            rolling average lb/TBtu
                                                            or lb/GWh emissions rates.
                                    OR                     OR
                                    LEE testing..........  a. Select sampling ports    Single point located at
                                                            location and the number     the 10% centroidal area
                                                            of traverse points.         of the duct at a port
                                                                                        location per Method 1 at
                                                                                        Appendix A-1 to part 60
                                                                                        of this chapter or
                                                                                        Method 30B at Appendix A-
                                                                                        8 for Method 30B point
                                                                                        selection.
                                                           b. Determine velocity and   Method 2, 2A, 2C, 2F, 2G,
                                                            volumetric flow-rate of     or 2H at Appendix A-1 or
                                                            the stack gas.              A-2 to part 60 of this
                                                                                        chapter or flow
                                                                                        monitoring system
                                                                                        certified per Appendix A
                                                                                        of this subpart.
                                                           c. Determine oxygen and     Method 3A or 3B at
                                                            carbon dioxide              Appendix A-1 to part 60
                                                            concentrations of the       of this chapter, or ANSI/
                                                            stack gas.                  ASME PTC 19.10-1981,\3\
                                                                                        or diluent gas
                                                                                        monitoring systems
                                                                                        certified according to
                                                                                        Part 75 of this chapter.
                                                           d. Measure the moisture     Method 4 at Appendix A-3
                                                            content of the stack gas.   to part 60 of this
                                                                                        chapter, or moisture
                                                                                        monitoring systems
                                                                                        certified according to
                                                                                        part 75 of this chapter.
                                                           e. Measure the Hg emission  Method 30B at Appendix A-
                                                            concentration.              8 to part 60 of this
                                                                                        chapter; perform a 30
                                                                                        operating day test, with
                                                                                        a maximum of 10
                                                                                        operating days per run
                                                                                        (i.e., per pair of
                                                                                        sorbent traps) or
                                                                                        sorbent trap monitoring
                                                                                        system or Hg CEMS
                                                                                        certified per Appendix A
                                                                                        of this subpart.
                                                           f. Convert emissions        Method 19 F-factor
                                                            concentrations from the     methodology at Appendix
                                                            LEE test to lb/TBtu or lb/  A-7 to part 60 of this
                                                            GWh emissions rates.        chapter, or calculate
                                                                                        using mass emissions
                                                                                        rate and electrical
                                                                                        output data (see Sec.
                                                                                        63.10007(e)).
                                                           g. Convert average lb/TBtu  Potential maximum annual
                                                            or lb/GWh Hg emission       heat input in TBtu or
                                                            rate to lb/year, if you     potential maximum
                                                            are attempting to meet      electricity generated in
                                                            the 22.0 lb/year            GWh.
                                                            threshold.
----------------------------------------------------------------------------------------------------------------
5. Sulfur dioxide (SO2)...........  SO2 CEMS.............  a. Install, certify,        Part 75 of this chapter
                                                            operate, and maintain the   and Sec.  Sec.
                                                            CEMS.                       63.10010(a) and (f).
                                                           b. Install, operate, and    Part 75 of this chapter
                                                            maintain the diluent gas,   and Sec.  Sec.
                                                            flow rate, and/or           63.10010(a), (b), (c),
                                                            moisture monitoring         and (d).
                                                            systems.
                                                           c. Convert hourly           Method 19 F-factor
                                                            emissions concentrations    methodology at Appendix
                                                            to 30 boiler operating      A-7 to part 60 of this
                                                            day rolling average lb/     chapter, or calculate
                                                            MMBtu or lb/MWh emissions   using mass emissions
                                                            rates.                      rate and electrical
                                                                                        output data (see Sec.
                                                                                        63.10007(e)).
----------------------------------------------------------------------------------------------------------------
\1\ Regarding emissions data collected during periods of startup or shutdown, see Sec.  Sec.   63.10020(b) and
  (c) and Sec.   63.10021(h).

[[Page 9497]]

 
\2\ See Tables 1 and 2 to this subpart for required sample volumes and/or sampling run times.
\3\ Incorporated by reference, see Sec.   63.14.
\4\ When using ASTM D6348-03, the following conditions must be met: (1) The test plan preparation and
  implementation in the Annexes to ASTM D6348-03, Sections A1 through A8 are mandatory; (2) For ASTM D6348-03
  Annex A5 (Analyte Spiking Technique), the percent (%) R must be determined for each target analyte (see
  Equation A5.5); (3) For the ASTM D6348-03 test data to be acceptable for a target analyte, %R must be 70% >= R
  <= 130%; and (4) The %R value for each compound must be reported in the test report and all field measurements
  corrected with the calculated %R value for that compound using the following equation:

  [GRAPHIC] [TIFF OMITTED] TR16FE12.011
  

                   Table 6 to Subpart UUUUU of Part 63--Establishing PM CPMS Operating Limits
    [As stated in Sec.   63.10007, you must comply with the following requirements for establishing operating
                                                     limits]
----------------------------------------------------------------------------------------------------------------
                                   And you choose to
    If you have an applicable      establish PM CPMS                                           According to the
    emission limit for . . .       operating limits,       And . . .          Using . . .          following
                                    you must . . .                                             procedures . . .
----------------------------------------------------------------------------------------------------------------
Particulate matter (PM), total    Install, certify,   Establish a site-   Data from the PM    1. Collect PM CPMS
 non-mercury HAP metals,           maintain, and       specific            CPMS and the PM     output data
 individual non-mercury HAP        operate a PM CPMS   operating limit     or HAP metals       during the entire
 metals, total HAP metals,         for monitoring      in units of PM      performance tests.  period of the
 individual HAP metals.            emissions           CPMS output                             performance
                                   discharged to the   signal (e.g.,                           tests.
                                   atmosphere          milliamps, mg/                         2. Record the
                                   according to Sec.   acm, or other raw                       average hourly PM
                                     63.10010(g)(1).   signal).                                CPMS output for
                                                                                               each test run in
                                                                                               the three run
                                                                                               performance test.
                                                                                              3. Determine the
                                                                                               highest 1-hour
                                                                                               average PM CPMS
                                                                                               measured during
                                                                                               the performance
                                                                                               test
                                                                                               demonstrating
                                                                                               compliance with
                                                                                               the filterable PM
                                                                                               or HAP metals
                                                                                               emissions
                                                                                               limitations.
----------------------------------------------------------------------------------------------------------------


Table 7 to Subpart UUUUU of Part 63--Demonstrating Continuous Compliance
 [As stated in Sec.   63.10021, you must show continuous compliance with
     the emission limitations for affected sources according to the
                               following]
------------------------------------------------------------------------
If you use one of the following to meet
 applicable emissions limits, operating     You demonstrate continuous
 limits, or work practice standards . .        compliance by . . .
                   .
------------------------------------------------------------------------
1. CEMS to measure filterable PM, SO2,   Calculating the 30-boiler
 HCl, HF, or Hg emissions, or using a     operating day rolling
 sorbent trap monitoring system to        arithmetic average emissions
 measure Hg.                              rate in units of the
                                          applicable emissions standard
                                          basis at the end of each
                                          boiler operating day using all
                                          of the quality assured hourly
                                          average CEMS or sorbent trap
                                          data for the previous 30
                                          boiler operating days,
                                          excluding data recorded during
                                          periods of startup or
                                          shutdown.
2. PM CPMS to measure compliance with a  Calculating the arithmetic 30-
 parametric operating limit.              boiler operating day rolling
                                          average of all of the quality
                                          assured hourly average PM CPMS
                                          output data (e.g., milliamps,
                                          PM concentration, raw data
                                          signal) collected for all
                                          operating hours for the
                                          previous 30 boiler operating
                                          days, excluding data recorded
                                          during periods of startup or
                                          shutdown.
3. Site-specific monitoring for liquid   If applicable, by conducting
 oil-fired units for HCl and HF           the monitoring in accordance
 emission limit monitoring.               with an approved site-specific
                                          monitoring plan.
4. Quarterly performance testing for     Calculating the results of the
 coal-fired, solid oil derived fired,     testing in units of the
 or liquid oil-fired units to measure     applicable emissions standard.
 compliance with one or more applicable
 emissions limit in Table 1 or 2.
5. Conducting periodic performance tune- Conducting periodic performance
 ups of your EGU(s).                      tune-ups of your EGU(s), as
                                          specified in Sec.
                                          63.10021(e).
6. Work practice standards for coal-     Operating in accordance with
 fired, liquid oil-fired, or solid oil-   Table 3.
 derived fuel-fired EGUs during startup.
7. Work practice standards for coal-     Operating in accordance with
 fired, liquid oil-fired, or solid oil-   Table 3.
 derived fuel-fired EGUs during
 shutdown.
------------------------------------------------------------------------


[[Page 9498]]


                           Table 8 to Subpart UUUUU of Part 63--Reporting Requirements
           [As stated in Sec.   63.10031, you must comply with the following requirements for reports]
----------------------------------------------------------------------------------------------------------------
                                                                                      You must submit the report
         You must submit a . . .                 The report must contain . . .                   . . .
----------------------------------------------------------------------------------------------------------------
1. Compliance report....................  a. Information required in Sec.             Semiannually according to
                                           63.10031(c)(1) through (4); and             the requirements in Sec.
                                          b. If there are no deviations from any        63.10031(b).
                                           emission limitation (emission limit and
                                           operating limit) that applies to you and
                                           there are no deviations from the
                                           requirements for work practice standards
                                           in Table 3 to this subpart that apply to
                                           you, a statement that there were no
                                           deviations from the emission limitations
                                           and work practice standards during the
                                           reporting period. If there were no
                                           periods during which the CMSs, including
                                           continuous emissions monitoring system,
                                           and operating parameter monitoring
                                           systems, were out-of-control as specified
                                           in Sec.   63.8(c)(7), a statement that
                                           there were no periods during which the
                                           CMSs were out-of-control during the
                                           reporting period; and.
                                          c. If you have a deviation from any         ..........................
                                           emission limitation (emission limit and
                                           operating limit) or work practice
                                           standard during the reporting period, the
                                           report must contain the information in
                                           Sec.   63.10031(d). If there were periods
                                           during which the CMSs, including
                                           continuous emissions monitoring systems
                                           and continuous parameter monitoring
                                           systems, were out-of-control, as
                                           specified in Sec.   63.8(c)(7), the
                                           report must contain the information in
                                           Sec.   63.10031(e).
----------------------------------------------------------------------------------------------------------------


Table 9 to Subpart UUUUU of Part 63--Applicability of General Provisions
                            to Subpart UUUUU
   [As stated in Sec.   63.10040, you must comply with the applicable
             General Provisions according to the following]
------------------------------------------------------------------------
                                                      Applies to subpart
            Citation                    Subject              UUUUU
------------------------------------------------------------------------
Sec.   63.1.....................  Applicability.....  Yes.
Sec.   63.2.....................  Definitions.......  Yes. Additional
                                                       terms defined in
                                                       Sec.   63.10042.
Sec.   63.3.....................  Units and           Yes.
                                   Abbreviations.
Sec.   63.4.....................  Prohibited          Yes.
                                   Activities and
                                   Circumvention.
Sec.   63.5.....................  Preconstruction     Yes.
                                   Review and
                                   Notification
                                   Requirements.
Sec.   63.6(a), (b)(1)-(b)(5),    Compliance with     Yes.
 (b)(7), (c), (f)(2)-(3), (g),     Standards and
 (h)(2)-(h)(9), (i), (j).          Maintenance
                                   Requirements.
Sec.   63.6(e)(1)(i)............  General Duty to     No. See Sec.
                                   minimize            63.10000(b) for
                                   emissions.          general duty
                                                       requirement.
Sec.   63.6(e)(1)(ii)...........  Requirement to      No.
                                   correct
                                   malfunctions ASAP.
Sec.   63.6(e)(3)...............  SSM Plan            No.
                                   requirements.
Sec.   63.6(f)(1)...............  SSM exemption.....  No.
Sec.   63.6(h)(1)...............  SSM exemption.....  No.
Sec.   63.7(a), (b), (c), (d),    Performance         Yes.
 (e)(2)-(e)(9), (f), (g), and      Testing
 (h).                              Requirements.
Sec.   63.7(e)(1)...............  Performance         No. See Sec.
                                   testing.            63.10007.
Sec.   63.8.....................  Monitoring          Yes.
                                   Requirements.
63.8(c)(1)(i)...................  General duty to     No. See Sec.
                                   minimize            63.10000(b) for
                                   emissions and CMS   general duty
                                   operation.          requirement.
Sec.   63.8(c)(1)(iii)..........  Requirement to      No.
                                   develop SSM Plan
                                   for CMS.
Sec.   63.8(d)(3)...............  Written procedures  Yes, except for
                                   for CMS.            last sentence,
                                                       which refers to
                                                       an SSM plan. SSM
                                                       plans are not
                                                       required.
Sec.   63.9.....................  Notification        Yes.
                                   Requirements.
Sec.   63.10(a), (b)(1), (c),     Recordkeeping and   Yes, except for
 (d)(1)-(2), (e), and (f).         Reporting           the requirements
                                   Requirements.       to submit written
                                                       reports under
                                                       Sec.
                                                       63.10(e)(3)(v).
Sec.   63.10(b)(2)(i)...........  Recordkeeping of    No.
                                   occurrence and
                                   duration of
                                   startups and
                                   shutdowns.
Sec.   63.10(b)(2)(ii)..........  Recordkeeping of    No. See 63.10001
                                   malfunctions.       for recordkeeping
                                                       of (1) occurrence
                                                       and duration and
                                                       (2) actions taken
                                                       during
                                                       malfunction.
Sec.   63.10(b)(2)(iii).........  Maintenance         Yes.
                                   records.
Sec.   63.10(b)(2)(iv)..........  Actions taken to    No.
                                   minimize
                                   emissions during
                                   SSM.
Sec.   63.10(b)(2)(v)...........  Actions taken to    No.
                                   minimize
                                   emissions during
                                   SSM.
Sec.   63.10(b)(2)(vi)..........  Recordkeeping for   Yes.
                                   CMS malfunctions.
Sec.   63.10(b)(2)(vii)-(ix)....  Other CMS           Yes.
                                   requirements.
Sec.   63.10(b)(3), and (d)(3)-   ..................  No.
 (5).
Sec.   63.10(c)(7)..............  Additional          Yes.
                                   recordkeeping
                                   requirements for
                                   CMS--identifying
                                   exceedances and
                                   excess emissions.
Sec.   63.10(c)(8)..............  Additional          Yes.
                                   recordkeeping
                                   requirements for
                                   CMS--identifying
                                   exceedances and
                                   excess emissions.
Sec.   63.10(c)(10).............  Recording nature    No. See
                                   and cause of        63.10032(g) and
                                   malfunctions.       (h) for
                                                       malfunctions
                                                       recordkeeping
                                                       requirements.

[[Page 9499]]

 
Sec.   63.10(c)(11).............  Recording           No. See
                                   corrective          63.10032(g) and
                                   actions.            (h) for
                                                       malfunctions
                                                       recordkeeping
                                                       requirements.
Sec.   63.10(c)(15).............  Use of SSM Plan...  No.
Sec.   63.10(d)(5)..............  SSM reports.......  No. See
                                                       63.10021(h) and
                                                       (i) for
                                                       malfunction
                                                       reporting
                                                       requirements.
Sec.   63.11....................  Control Device      No.
                                   Requirements.
Sec.   63.12....................  State Authority     Yes.
                                   and Delegation.
Sec.   63.13-63.16..............  Addresses,          Yes.
                                   Incorporation by
                                   Reference,
                                   Availability of
                                   Information,
                                   Performance Track
                                   Provisions.
Sec.   63.1(a)(5), (a)(7)-        Reserved..........  No.
 (a)(9), (b)(2), (c)(3)-(4),
 (d), 63.6(b)(6), (c)(3),
 (c)(4), (d), (e)(2),
 (e)(3)(ii), (h)(3), (h)(5)(iv),
 63.8(a)(3), 63.9(b)(3), (h)(4),
 63.10(c)(2)-(4), (c)(9).
------------------------------------------------------------------------

Appendix A to Subpart UUUUU--Hg Monitoring Provisions

1. General Provisions

    1.1 Applicability. These monitoring provisions apply to the 
measurement of total vapor phase mercury (Hg) in emissions from 
electric utility steam generating units, using either a mercury 
continuous emission monitoring system (Hg CEMS) or a sorbent trap 
monitoring system. The Hg CEMS or sorbent trap monitoring system 
must be capable of measuring the total vapor phase mercury in units 
of the applicable emissions standard (e.g., lb/TBtu or lb/GWh), 
regardless of speciation.
    1.2 Initial Certification and Recertification Procedures. The 
owner or operator of an affected unit that uses a Hg CEMS or a 
sorbent trap monitoring system together with other necessary 
monitoring components to account for Hg emissions in units of the 
applicable emissions standard shall comply with the initial 
certification and recertification procedures in section 4 of this 
appendix.
    1.3 Quality Assurance and Quality Control Requirements. The 
owner or operator of an affected unit that uses a Hg CEMS or a 
sorbent trap monitoring system together with other necessary 
monitoring components to account for Hg emissions in units of the 
applicable emissions standard shall meet the applicable quality 
assurance requirements in section 5 of this appendix.
    1.4 Missing Data Procedures. The owner or operator of an 
affected unit is not required to substitute for missing data from Hg 
CEMS or sorbent trap monitoring systems. Any process operating hour 
for which quality-assured Hg concentration data are not obtained is 
counted as an hour of monitoring system downtime.

2. Monitoring of Hg Emissions

    2.1 Monitoring System Installation Requirements. Flue gases from 
the affected units under this subpart vent to the atmosphere through 
a variety of exhaust configurations including single stacks, common 
stack configurations, and multiple stack configurations. For each of 
these configurations, Sec.  63.10010(a) specifies the appropriate 
location(s) at which to install continuous monitoring systems (CMS). 
These CMS installation provisions apply to the Hg CEMS, sorbent trap 
monitoring systems, and other continuous monitoring systems that 
provide data for the Hg emissions calculations in section 6.2 of 
this appendix.
    2.2 Primary and Backup Monitoring Systems. In the electronic 
monitoring plan described in section 7.1.1.2.1 of this appendix, you 
must designate a primary Hg CEMS or sorbent trap monitoring system. 
The primary system must be used to report hourly Hg concentration 
values when the system is able to provide quality-assured data, 
i.e., when the system is ``in control''. However, to increase data 
availability in the event of a primary monitoring system outage, you 
may install, operate, maintain, and calibrate backup monitoring 
systems, as follows:
    2.2.1 Redundant Backup Systems. A redundant backup monitoring 
system may be either a separate Hg CEMS with its own probe, sample 
interface, and analyzer, or a separate sorbent trap monitoring 
system. A redundant backup system is one that is permanently 
installed at the unit or stack location, and is kept on ``hot 
standby'' in case the primary monitoring system is unable to provide 
quality-assured data. A redundant backup system must be represented 
as a unique monitoring system in the electronic monitoring plan. 
Each redundant backup monitoring system must be certified according 
to the applicable provisions in section 4 of this appendix and must 
meet the applicable on-going QA requirements in section 5 of this 
appendix.
    2.2.2 Non-redundant Backup Monitoring Systems. A non-redundant 
backup monitoring system is a separate Hg CEMS or sorbent trap 
system that has been certified at a particular unit or stack 
location, but is not permanently installed at that location. Rather, 
the system is kept on ``cold standby'' and may be reinstalled in the 
event of a primary monitoring system outage. A non-redundant backup 
monitoring system must be represented as a unique monitoring system 
in the electronic monitoring plan. Non-redundant backup Hg CEMS must 
complete the same certification tests as the primary monitoring 
system, with one exception. The 7-day calibration error test is not 
required for a non-redundant backup Hg CEMS. Except as otherwise 
provided in section 2.2.4.5 of this appendix, a non-redundant backup 
monitoring system may only be used for 720 hours per year at a 
particular unit or stack location.
    2.2.3 Temporary Like-kind Replacement Analyzers. When a primary 
Hg analyzer needs repair or maintenance, you may temporarily install 
a like-kind replacement analyzer, to minimize data loss. Except as 
otherwise provided in section 2.2.4.5 of this appendix, a temporary 
like-kind replacement analyzer may only be used for 720 hours per 
year at a particular unit or stack location. The analyzer must be 
represented as a component of the primary Hg CEMS, and must be 
assigned a 3-character component ID number, beginning with the 
prefix ``LK''.
    2.2.4 Quality Assurance Requirements for Non-redundant Backup 
Monitoring Systems and Temporary Like-kind Replacement Analyzers. To 
quality-assure the data from non-redundant backup Hg monitoring 
systems and temporary like-kind replacement Hg analyzers, the 
following provisions apply:
    2.2.4.1 When a certified non-redundant backup sorbent trap 
monitoring system is brought into service, you must follow the 
procedures for routine day-to-day operation of the system, in 
accordance with Performance Specification (PS) 12B in appendix B to 
part 60 of this chapter.
    2.2.4.2 When a certified non-redundant backup Hg CEMS or a 
temporary like-kind replacement Hg analyzer is brought into service, 
a calibration error test and a linearity check must be performed and 
passed. A single point system integrity check is also required, 
unless a NIST-traceable source of oxidized Hg was used for the 
calibration error test.
    2.2.4.3 Each non-redundant backup Hg CEMS or temporary like-kind 
replacement Hg analyzer shall comply with all required daily, 
weekly, and quarterly quality-assurance test requirements in section 
5 of this appendix, for as long as the system or analyzer remains in 
service.
    2.2.4.4 For the routine, on-going quality-assurance of a non-
redundant backup Hg monitoring system, a relative accuracy test 
audit (RATA) must be performed and passed at least once every 8 
calendar quarters at the

[[Page 9500]]

unit or stack location(s) where the system will be used.
    2.2.4.5 To use a non-redundant backup Hg monitoring system or a 
temporary like-kind replacement analyzer for more than 720 hours per 
year at a particular unit or stack location, a RATA must first be 
performed and passed at that location.

3. Mercury Emissions Measurement Methods

    The following definitions, equipment specifications, procedures, 
and performance criteria are applicable to the measurement of vapor-
phase Hg emissions from electric utility steam generating units, 
under relatively low-dust conditions (i.e., sampling in the stack or 
duct after all pollution control devices). The analyte measured by 
these procedures and specifications is total vapor-phase Hg in the 
flue gas, which represents the sum of elemental Hg (Hg0, 
CAS Number 7439-97-6) and oxidized forms of Hg.
    3.1 Definitions.
    3.1.1 Mercury Continuous Emission Monitoring System or Hg CEMS 
means all of the equipment used to continuously determine the total 
vapor phase Hg concentration. The measurement system may include the 
following major subsystems: sample acquisition, Hg+2 to 
Hg0 converter, sample transport, sample conditioning, 
flow control/gas manifold, gas analyzer, and data acquisition and 
handling system (DAHS). Hg CEMS may be nominally real-time or time-
integrated, batch sampling systems that sample the gas on an 
intermittent basis and concentrate on a collection medium before 
intermittent analysis and reporting.
    3.1.2 Sorbent Trap Monitoring System means the equipment 
required to monitor Hg emissions continuously by using paired 
sorbent traps containing iodated charcoal (IC) or other suitable 
sorbent medium. The monitoring system consists of a probe, paired 
sorbent traps, an umbilical line, moisture removal components, an 
airtight sample pump, a gas flow meter, and an automated data 
acquisition and handling system. The system samples the stack gas at 
a constant proportional rate relative to the stack gas volumetric 
flow rate. The sampling is a batch process. The average Hg 
concentration in the stack gas for the sampling period is 
determined, in units of micrograms per dry standard cubic meter 
([mu]g/dscm), based on the sample volume measured by the gas flow 
meter and the mass of Hg collected in the sorbent traps.
    3.1.3 NIST means the National Institute of Standards and 
Technology, located in Gaithersburg, Maryland.
    3.1.4 NIST-Traceable Elemental Hg Standards means either: 
compressed gas cylinders having known concentrations of elemental 
Hg, which have been prepared according to the ``EPA Traceability 
Protocol for Assay and Certification of Gaseous Calibration 
Standards''; or calibration gases having known concentrations of 
elemental Hg, produced by a generator that meets the performance 
requirements of the ``EPA Traceability Protocol for Qualification 
and Certification of Elemental Mercury Gas Generators'' or an 
interim version of that protocol.
    3.1.5 NIST-Traceable Source of Oxidized Hg means a generator 
that is capable of providing known concentrations of vapor phase 
mercuric chloride (HgCl2), and that meets the performance 
requirements of the ``EPA Traceability Protocol for Qualification 
and Certification of Mercuric Chloride Gas Generators'' or an 
interim version of that protocol.
    3.1.6 Calibration Gas means a NIST-traceable gas standard 
containing a known concentration of elemental or oxidized Hg that is 
produced and certified in accordance with an EPA traceability 
protocol.
    3.1.7 Span Value means a conservatively high estimate of the Hg 
concentrations to be measured by a CEMS. The span value of a Hg CEMS 
should be set to approximately twice the concentration corresponding 
to the emission standard, rounded off as appropriate (see section 
3.2.1.4.2 of this appendix).
    3.1.8 Zero-Level Gas means calibration gas containing a Hg 
concentration that is below the level detectable by the Hg gas 
analyzer in use.
    3.1.9 Low-Level Gas means calibration gas with a concentration 
that is 20 to 30 percent of the span value.
    3.1.10 Mid-Level Gas means calibration gas with a concentration 
that is 50 to 60 percent of the span value.
    3.1.11 High-Level Gas means calibration gas with a concentration 
that is 80 to 100 percent of the span value.
    3.1.12 Calibration Error Test means a test designed to assess 
the ability of a Hg CEMS to measure the concentrations of 
calibration gases accurately. A zero-level gas and an upscale gas 
are required for this test. For the upscale gas, either a mid-level 
gas or a high-level gas may be used, and the gas may either be an 
elemental or oxidized Hg standard.
    3.1.13 Linearity Check means a test designed to determine 
whether the response of a Hg analyzer is linear across its 
measurement range. Three elemental Hg calibration gas standards 
(i.e., low, mid, and high-level gases) are required for this test.
    3.1.14 System Integrity Check means a test designed to assess 
the transport and measurement of oxidized Hg by a Hg CEMS. Oxidized 
Hg standards are used for this test. For a three-level system 
integrity check, low, mid, and high-level calibration gases are 
required. For a single-level check, either a mid-level gas or a 
high-level gas may be used.
    3.1.15 Cycle Time Test means a test designed to measure the 
amount of time it takes for a Hg CEMS, while operating normally, to 
respond to a known step change in gas concentration. For this test, 
a zero gas and a high-level gas are required. The high-level gas may 
be either an elemental or an oxidized Hg standard.
    3.1.16 Relative Accuracy Test Audit or RATA means a series of 
nine or more test runs, directly comparing readings from a Hg CEMS 
or sorbent trap monitoring system to measurements made with a 
reference stack test method. The relative accuracy (RA) of the 
monitoring system is expressed as the absolute mean difference 
between the monitoring system and reference method measurements plus 
the absolute value of the 2.5 percent error confidence coefficient, 
divided by the mean value of the reference method measurements.
    3.1.17 Unit Operating Hour means a clock hour in which a unit 
combusts any fuel, either for part of the hour or for the entire 
hour.
    3.1.18 Stack Operating Hour means a clock hour in which gases 
flow through a particular monitored stack or duct (either for part 
of the hour or for the entire hour), while the associated unit(s) 
are combusting fuel.
    3.1.19 Operating Day means a calendar day in which a source 
combusts any fuel.
    3.1.20 Quality Assurance (QA) Operating Quarter means a calendar 
quarter in which there are at least 168 unit or stack operating 
hours (as defined in this section).
    3.1.21 Grace Period means a specified number of unit or stack 
operating hours after the deadline for a required quality-assurance 
test of a continuous monitor has passed, in which the test may be 
performed and passed without loss of data.
    3.2 Continuous Monitoring Methods.
    3.2.1 Hg CEMS. A typical Hg CEMS is shown in Figure A-1. The 
CEMS in Figure A-1 is a dilution extractive system, which measures 
Hg concentration on a wet basis, and is the most commonly-used type 
of Hg CEMS. Other system designs may be used, provided that the CEMS 
meets the performance specifications in section 4.1.1 of this 
appendix.

[[Page 9501]]

[GRAPHIC] [TIFF OMITTED] TR16FE12.012

    3.2.1.1 Equipment Specifications.
    3.2.1.1.1 Materials of Construction. All wetted sampling system 
components, including probe components prior to the point at which 
the calibration gas is introduced, must be chemically inert to all 
Hg species. Materials such as perfluoroalkoxy (PFA) Teflon\TM\, 
quartz, and treated stainless steel (SS) are examples of such 
materials.
    3.2.1.1.2 Temperature Considerations. All system components 
prior to the Hg+2 to Hg\0\ converter must be maintained 
at a sample temperature above the acid gas dew point.
    3.2.1.1.3 Measurement System Components.
    3.2.1.1.3.1 Sample Probe. The probe must be made of the 
appropriate materials as noted in paragraph 3.2.1.1.1 of this 
section, heated when necessary, as described in paragraph 
3.2.1.1.3.4 of this section, and configured with ports for 
introduction of calibration gases.
    3.2.1.1.3.2 Filter or Other Particulate Removal Device. The 
filter or other particulate removal device is part of the 
measurement system, must be made of appropriate materials, as noted 
in paragraph 3.2.1.1.1 of this section, and must be included in all 
system tests.
    3.2.1.1.3.3 Sample Line. The sample line that connects the probe 
to the converter, conditioning system, and analyzer must be made of 
appropriate materials, as noted in paragraph 3.2.1.1.1 of this 
section.
    3.2.1.1.3.4 Conditioning Equipment. For wet basis systems, such 
as the one shown in Figure A-1, the sample must be kept above its 
dew point either by: heating the sample line and all sample 
transport components up to the inlet of the analyzer (and, for hot-
wet extractive systems, also heating the analyzer); or diluting the 
sample prior to analysis using a dilution probe system. The 
components required for these operations are considered to be 
conditioning equipment. For dry basis measurements, a condenser, 
dryer or other suitable device is required to remove moisture 
continuously from the sample gas, and any equipment needed to heat 
the probe or sample line to avoid condensation prior to the moisture 
removal component is also required.
    3.2.1.1.3.5 Sampling Pump. A pump is needed to push or pull the 
sample gas through the system at a flow rate sufficient to minimize 
the response time of the measurement system. If a mechanical sample 
pump is used and its surfaces are in contact with the sample gas 
prior to detection, the pump must be leak free and must be 
constructed of a material that is non-reactive to the gas being 
sampled (see paragraph 3.2.1.1.1 of this section). For dilution-type 
measurement systems, such as the system shown in Figure A-1, an 
ejector pump (eductor) may be used to create a sufficient vacuum 
that sample gas will be drawn through a critical orifice at a 
constant rate. The ejector pump must be constructed of any material 
that is non-reactive to the gas being sampled.
    3.2.1.1.3.6 Calibration Gas System(s). Design and equip each Hg 
CEMS to permit the introduction of known concentrations of elemental 
Hg and HgCl2 separately, at a point preceding the sample 
extraction filtration system, such that the entire measurement 
system can be checked. The calibration gas system(s) must be 
designed so that the flow rate exceeds the sampling system flow 
requirements and that the gas is delivered to the CEMS at 
atmospheric pressure.
    3.2.1.1.3.7 Sample Gas Delivery. The sample line may feed 
directly to either a converter, a by-pass valve (for Hg speciating 
systems), or a sample manifold. All valve and/or manifold components 
must be made of material that is non-reactive to the gas sampled and 
the calibration gas, and must be configured to safely discharge any 
excess gas.
    3.2.1.1.3.8 Hg Analyzer. An instrument is required that 
continuously measures the total vapor phase Hg concentration in the 
gas stream. The analyzer may also be capable of measuring elemental 
and oxidized Hg separately.
    3.2.1.1.3.9 Data Recorder. A recorder, such as a computerized 
data acquisition and handling system (DAHS), digital recorder, or 
data logger, is required for recording measurement data.
    3.2.1.2 Reagents and Standards.
    3.2.1.2.1 NIST Traceability. Only NIST-certified or NIST-
traceable calibration gas standards and reagents (as defined in 
paragraphs 3.1.4 and 3.1.5 of this section) shall be used for the 
tests and procedures required under this subpart. Calibration gases 
with known concentrations of Hg0 and HgCl2 are 
required. Special reagents and equipment may be needed to prepare 
the Hg0 and HgCl2 gas standards (e.g., NIST-
traceable solutions of HgCl2 and gas generators equipped 
with mass flow controllers).
    3.2.1.2.2 Required Calibration Gas Concentrations.
    3.2.1.2.2.1 Zero-Level Gas. A zero-level calibration gas with a 
Hg concentration below the level detectable by the Hg analyzer is 
required for calibration error tests and cycle time tests of the 
CEMS.
    3.2.1.2.2.2 Low-Level Gas. A low-level calibration gas with a Hg 
concentration of 20 to 30 percent of the span value is required for 
linearity checks and 3-level system integrity checks of the CEMS. 
Elemental Hg standards are required for the linearity checks and 
oxidized Hg standards are required for the system integrity checks.
    3.2.1.2.2.3 Mid-Level Gas. A mid-level calibration gas with a Hg 
concentration of 50

[[Page 9502]]

to 60 percent of the span value is required for linearity checks and 
for 3-level system integrity checks of the CEMS, and is optional for 
calibration error tests and single-level system integrity checks. 
Elemental Hg standards are required for the linearity checks, 
oxidized Hg standards are required for the system integrity checks, 
and either elemental or oxidized Hg standards may be used for the 
calibration error tests.
    3.2.1.2.2.4 High-Level Gas. A high-level calibration gas with a 
Hg concentration of 80 to 100 percent of the span value is required 
for linearity checks, 3-level system integrity checks, and cycle 
time tests of the CEMS, and is optional for calibration error tests 
and single-level system integrity checks. Elemental Hg standards are 
required for the linearity checks, oxidized Hg standards are 
required for the system integrity checks, and either elemental or 
oxidized Hg standards may be used for the calibration error and 
cycle time tests.
    3.2.1.3 Installation and Measurement Location. For the Hg CEMS 
and any additional monitoring system(s) needed to convert Hg 
concentrations to the desired units of measure (i.e., a flow 
monitor, CO2 or O2 monitor, and/or moisture 
monitor, as applicable), install each monitoring system at a 
location: that is consistent with 63.10010(a); that represents the 
emissions exiting to the atmosphere; and where it is likely that the 
CEMS can pass the relative accuracy test.
    3.2.1.4 Monitor Span and Range Requirements. Determine the 
appropriate span and range value(s) for the Hg CEMS as described in 
paragraphs 3.2.1.4.1 through 3.2.1.4.3 of this section.
    3.2.1.4.1 Maximum Potential Concentration. There are three 
options for determining the maximum potential Hg concentration 
(MPC). Option 1 applies to coal combustion. You may use a default 
value of 10 [mu]g/scm for all coal ranks (including coal refuse) 
except for lignite; for lignite, use 16 [mu]g/scm. If different 
coals are blended as part of normal operation, use the highest MPC 
for any fuel in the blend. Option 2 is to base the MPC on the 
results of site-specific Hg emission testing. This option may be 
used only if the unit does not have add-on Hg emission controls or a 
flue gas desulfurization system, or if testing is performed upstream 
of all emission control devices. If Option 2 is selected, perform at 
least three test runs at the normal operating load, and the highest 
Hg concentration obtained in any of the tests shall be the MPC. 
Option 3 is to use fuel sampling and analysis to estimate the MPC. 
To make this estimate, use the average Hg content (i.e., the weight 
percentage) from at least three representative fuel samples, 
together with other available information, including, but not 
limited to the maximum fuel feed rate, the heating value of the 
fuel, and an appropriate F-factor. Assume that all of the Hg in the 
fuel is emitted to the atmosphere as vapor-phase Hg.
    3.2.1.4.2 Span Value. To determine the span value of the Hg 
CEMS, multiply the Hg concentration corresponding to the applicable 
emissions standard by two. If the result of this calculation is an 
exact multiple of 10 [mu]g/scm, use the result as the span value. 
Otherwise, round off the result to either: the next highest integer; 
the next highest multiple of 5 [mu]g/scm; or the next highest 
multiple of 10 [mu]g/scm.
    3.2.1.4.3 Analyzer Range. The Hg analyzer must be capable of 
reading Hg concentration as high as the MPC.
    3.2.2 Sorbent Trap Monitoring System. A sorbent trap monitoring 
system (as defined in paragraph 3.1.2 of this section) may be used 
as an alternative to a Hg CEMS. If this option is selected, the 
monitoring system shall be installed, maintained, and operated in 
accordance with Performance Specification (PS) 12B in Appendix B to 
part 60 of this chapter. The system shall be certified in accordance 
with the provisions of section 4.1.2 of this appendix.
    3.2.3 Other Necessary Data Collection. To convert measured 
hourly Hg concentrations to the units of the applicable emissions 
standard (i.e., lb/TBtu or lb/GWh), additional data must be 
collected, as described in paragraphs 3.2.3.1 through 3.2.3.3 of 
this section. Any additional monitoring systems needed for this 
purpose must be certified, operated, maintained, and quality-assured 
according to the applicable provisions of part 75 of this chapter 
(see Sec. Sec.  63.10010(b) through (d)). The calculation methods 
for the types of emission limits described in paragraphs 3.2.3.1 and 
3.2.3.2 of this section are presented in section 6.2 of this 
appendix.
    3.2.3.1 Heat Input-Based Emission Limits. For a heat input-based 
Hg emission limit (i.e., in lb/TBtu), data from a certified 
CO2 or O2 monitor are needed, along with a 
fuel-specific F-factor and a conversion constant to convert measured 
Hg concentration values to the units of the standard. In some cases, 
the stack gas moisture content must also be considered in making 
these conversions.
    3.2.3.2 Electrical Output-Based Emission Rates. If the 
applicable Hg limit is electrical output-based (i.e., lb/GWh), 
hourly electrical load data and unit operating times are required in 
addition to hourly data from a certified stack gas flow rate monitor 
and (if applicable) moisture data.
    3.2.3.3 Sorbent Trap Monitoring System Operation. Routine 
operation of a sorbent trap monitoring system requires the use of a 
certified stack gas flow rate monitor, to maintain an established 
ratio of stack gas flow rate to sample flow rate.

4. Certification and Recertification Requirements

    4.1 Certification Requirements. All Hg CEMS and sorbent trap 
monitoring systems and the additional monitoring systems used to 
continuously measure Hg emissions in units of the applicable 
emissions standard in accordance with this appendix must be 
certified in a timely manner, such that the initial compliance 
demonstration is completed no later than the applicable date in 
Sec.  63.10005(g).
    4.1.1 Hg CEMS. Table A-1, below, summarizes the certification 
test requirements and performance specifications for a Hg CEMS. The 
CEMS may not be used to report quality-assured data until these 
performance criteria are met. Paragraphs 4.1.1.1 through 4.1.1.5 of 
this section provide specific instructions for the required tests. 
All tests must be performed with the affected unit(s) operating 
(i.e., combusting fuel). Except for the RATA, which must be 
performed at normal load, no particular load level is required for 
the certification tests.
    4.1.1.1 7-Day Calibration Error Test. Perform the 7-day 
calibration error test on 7 consecutive source operating days, using 
a zero-level gas and either a high-level or a mid-level calibration 
gas standard (as defined in sections 3.1.8, 3.1.10, and 3.1.11 of 
this appendix). Either elemental or oxidized NIST-traceable Hg 
standards (as defined in sections 3.1.4 and 3.1.5 of this appendix) 
may be used for the test. If moisture and/or chlorine is added to 
the calibration gas, the dilution effect of the moisture and/or 
chlorine addition on the calibration gas concentration must be 
accounted for in an appropriate manner. Operate the Hg CEMS in its 
normal sampling mode during the test. The calibrations should be 
approximately 24 hours apart, unless the 7-day test is performed 
over nonconsecutive calendar days. On each day of the test, inject 
the zero-level and upscale gases in sequence and record the analyzer 
responses. Pass the calibration gas through all filters, scrubbers, 
conditioners, and other monitor components used during normal 
sampling, and through as much of the sampling probe as is practical. 
Do not make any manual adjustments to the monitor (i.e., resetting 
the calibration) until after taking measurements at both the zero 
and upscale concentration levels. If automatic adjustments are made 
following both injections, conduct the calibration error test such 
that the magnitude of the adjustments can be determined, and use 
only the unadjusted analyzer responses in the calculations. 
Calculate the calibration error (CE) on each day of the test, as 
described in Table A-1. The CE on each day of the test must either 
meet the main performance specification or the alternative 
specification in Table A-1.
    4.1.1.2 Linearity Check. Perform the linearity check using low, 
mid, and high-level concentrations of NIST-traceable elemental Hg 
standards. Three gas injections at each concentration level are 
required, with no two successive injections at the same 
concentration level. Introduce the calibration gas at the gas 
injection port, as specified in section 3.2.1.1.3.6 of this 
appendix. Operate the CEMS at its normal operating temperature and 
conditions. Pass the calibration gas through all filters, scrubbers, 
conditioners, and other components used during normal sampling, and 
through as much of the sampling probe as is practical. If moisture 
and/or chlorine is added to the calibration gas, the dilution effect 
of the moisture and/or chlorine addition on the calibration gas 
concentration must be accounted for in an appropriate manner. Record 
the monitor response from the data acquisition and handling system 
for each gas injection. At each concentration level, use the average 
analyzer response to calculate the linearity error (LE), as 
described in Table A-1. The LE must either meet the main performance 
specification or the alternative specification in Table A-1.
    4.1.1.3 Three-Level System Integrity Check. Perform the 3-level 
system integrity

[[Page 9503]]

check using low, mid, and high-level calibration gas concentrations 
generated by a NIST-traceable source of oxidized Hg. Follow the same 
basic procedure as for the linearity check. If moisture and/or 
chlorine is added to the calibration gas, the dilution effect of the 
moisture and/or chlorine addition on the calibration gas 
concentration must be accounted for in an appropriate manner. 
Calculate the system integrity error (SIE), as described in Table A-
1. The SIE must either meet the main performance specification or 
the alternative specification in Table A-1. (Note: This test is not 
required if the CEMS does not have a converter).

               Table A-1--Required Certification Tests and Performance Specifications for Hg CEMS
----------------------------------------------------------------------------------------------------------------
                                                                     The alternate
 For this required certification test    The main performance         performance         And the conditions of
                . . .                   specification \1\ is .   specification \1\ is .       the alternate
                                                 . .                      . .            specification are . . .
----------------------------------------------------------------------------------------------------------------
7-day calibration error test \2\.....  [verbarlm]R - A          [verbarlm]R - A          The alternate
                                        [verbarlm] <=5.0% of     [verbarlm] <=1.0         specification may be
                                        span value, for both     [micro]g/scm.            used on any day of the
                                        the zero and upscale                              test.
                                        gases, on each of the
                                        7 days.
Linearity check \3\..................  [verbarlm]R - Aavg       [verbarlm]R - Aavg       The alternate
                                        [verbarlm] <=10.0% of    [verbarlm] <=0.8         specification may be
                                        the reference gas        [micro]g/scm.            used at any gas level.
                                        concentration at each
                                        calibration gas level
                                        (low, mid, or high).
3-level system integrity check \4\...  [verbarlm]R - Aavg       [verbarlm]R - Aavg       The alternate
                                        [verbarlm] <=10.0% of    [verbarlm] <=0.8         specification may be
                                        the reference gas        [micro]g/scm.            used at any gas level.
                                        concentration at each
                                        calibration gas level.
RATA.................................  20.0% RA...............  [verbarlm]RMavg - Cavg   RMavg <5.0 [micro]g/
                                                                 [verbarlm] <=1.0         scm.
                                                                 [micro]g/scm**.
Cycle time test \2\..................  15 minutes.\5\
----------------------------------------------------------------------------------------------------------------
\1\ Note that [verbarlm]R - A [verbarlm] is the absolute value of the difference between the reference gas value
  and the analyzer reading. [verbarlm]R - Aavg, [verbarlm] is the absolute value of the difference between the
  reference gas concentration and the average of the analyzer responses, at a particular gas level.
\2\ Use either elemental or oxidized Hg standards; a mid-level or high-level upscale gas may be used. This test
  is not required for Hg CEMS that use integrated batch sampling; however, those monitors must be capable of
  recording at least one Hg concentration reading every 15 minutes.
\3\ Use elemental Hg standards.
\4\ Use oxidized Hg standards. Not required if the CEMS does not have a converter.
\5\ Stability criteria--Readings change by <2.0% of span or by <=0.5 [micro]g/scm, for 2 minutes.
** Note that [verbarlm]RMavg-Cavg [verbarlm] is the absolute difference between the mean reference method value
  and the mean CEMS value from the RATA. The arithmetic difference between RMavg and Cavg can be either + or -.

    4.1.1.4 Cycle Time Test. Perform the cycle time test, using a 
zero-level gas and a high-level calibration gas.
    Either an elemental or oxidized NIST-traceable Hg standard may 
be used as the high-level gas. Perform the test in two stages--
upscale and downscale. The slower of the upscale and downscale 
response times is the cycle time for the CEMS. Begin each stage of 
the test by injecting calibration gas after achieving a stable 
reading of the stack emissions. The cycle time is the amount of time 
it takes for the analyzer to register a reading that is 95 percent 
of the way between the stable stack emissions reading and the final, 
stable reading of the calibration gas concentration. Use the 
following criterion to determine when a stable reading of stack 
emissions or calibration gas has been attained--the reading is 
stable if it changes by no more than 2.0 percent of the span value 
or 0.5 [micro]g/scm (whichever is less restrictive) for two minutes, 
or a reading with a change of less than 6.0 percent from the 
measured average concentration over 6 minutes. Integrated batch 
sampling type Hg CEMS are exempted from this test; however, these 
systems must be capable of delivering a measured Hg concentration 
reading at least once every 15 minutes. If necessary to increase 
measurement sensitivity of a batch sampling type Hg CEMS for a 
specific application, you may petition the Administrator for 
approval of a time longer than 15 minutes between readings.
    4.1.1.5 Relative Accuracy Test Audit (RATA). Perform the RATA of 
the Hg CEMS at normal load. Acceptable Hg reference methods for the 
RATA include ASTM D6784-02 (Reapproved 2008), ``Standard Test Method 
for Elemental, Oxidized, Particle-Bound and Total Mercury in Flue 
Gas Generated from Coal-Fired Stationary Sources (Ontario Hydro 
Method)'' (incorporated by reference, see Sec.  63.14) and Methods 
29, 30A, and 30B in appendix A-8 to part 60. When Method 29 or ASTM 
D6784-02 is used, paired sampling trains are required. To validate a 
Method 29 or ASTM D6784-02 test run, calculate the relative 
deviation (RD) using Equation A-1 of this section, and assess the 
results as follows to validate the run. The RD must not exceed 10 
percent, when the average Hg concentration is greater than 1.0 
[micro]g/dscm. If the average concentration is <= 1.0 [micro]g/dscm, 
the RD must not exceed 20 percent. The RD results are also 
acceptable if the absolute difference between the two Hg 
concentrations does not exceed 0.2 [micro]g/dscm. If the RD 
specification is met, the results of the two samples shall be 
averaged arithmetically.
[GRAPHIC] [TIFF OMITTED] TR16FE12.013

Where:

RD = Relative deviation between the Hg concentrations of samples 
``a'' and ``b'' (percent)
Ca = Hg concentration of Hg sample ``a'' ([mu]g/dscm)
Cb = Hg concentration of Hg sample ``b'' ([mu]g/dscm)

    4.1.1.5.1 Special Considerations. A minimum of nine valid test 
runs must be performed, directly comparing the CEMS measurements to 
the reference method. More than nine test runs may be performed. If 
this option is chosen, the results from a maximum of three test runs 
may be rejected so long as the total number of test results used to 
determine the relative accuracy is greater than or equal to nine; 
however, all data must be reported including the rejected data. The 
minimum time per run is 21 minutes if Method 30A is used. If Method 
29, Method 30B, or ASTM D6784-02 (Reapproved 2008), ``Standard Test 
Method for Elemental, Oxidized, Particle-Bound and Total Mercury in 
Flue Gas Generated from Coal-Fired Stationary Sources (Ontario Hydro 
Method)'' (incorporated by reference, see Sec.  63.14) is used, the 
time per run must be long enough to collect a sufficient mass of Hg 
to analyze. Complete the RATA within 168 unit operating hours, 
except when Method 29 or ASTM D6784-02 is used, in which case up to 
336 operating hours may be taken to finish the test.
    4.1.1.5.2 Calculation of RATA Results. Calculate the relative 
accuracy (RA) of the monitoring system, on a [micro]g/scm basis, as 
described in section 12 of Performance Specification (PS) 2 in 
Appendix B to part 60 of this chapter (see Equations 2-3 through 2-6 
of PS2). For purposes of calculating the relative accuracy, ensure 
that the reference method and monitoring system data are on a 
consistent moisture basis, either wet or dry. The CEMS must either 
meet the main performance specification or the alternative 
specification in Table A-1.
    4.1.1.5.3 Bias Adjustment. Measurement or adjustment of Hg CEMS 
data for bias is not required.
    4.1.2 Sorbent Trap Monitoring Systems. For the initial 
certification of a sorbent trap monitoring system, only a RATA is 
required.
    4.1.2.1 Reference Methods. The acceptable reference methods for 
the RATA of a sorbent trap monitoring system are the same as those 
listed in paragraph 4.1.1.5 of this section.
    4.1.2.2 ``The special considerations specified in paragraph 
4.1.1.5.1 of this section apply to the RATA of a sorbent trap

[[Page 9504]]

monitoring system. During the RATA, the monitoring system must be 
operated and quality-assured in accordance with Performance 
Specification (PS) 12B in Appendix B to part 60 of this chapter with 
the following exceptions for sorbent trap section 2 breakthrough:
    4.1.2.2.1 For stack Hg concentrations >1 [micro]g/dscm, <=10% of 
section 1 Hg mass;
    4.1.2.2.2 For stack Hg concentrations <=1 [micro]g/dscm and >0.5 
[micro]g/dscm, <= 20% of section 1 Hg mass;
    4.1.2.2.3 For stack Hg concentrations <=0.5 [micro]g/dscm and 
>0.1 [micro]g/dscm, <= 50% of section 1 Hg mass; and
    4.1.2.2.4 For stack Hg concentrations <=0.1[micro]g/dscm, no 
breakthrough criterion assuming all other QA/QC specifications are 
met.
    4.1.2.3 The type of sorbent material used by the traps during 
the RATA must be the same as for daily operation of the monitoring 
system; however, the size of the traps used for the RATA may be 
smaller than the traps used for daily operation of the system.
    4.1.2.4 Calculation of RATA Results. Calculate the relative 
accuracy (RA) of the sorbent trap monitoring system, on a [micro]g/
scm basis, as described in section 12 of Performance Specification 
(PS) 2 in appendix B to part 60 of this chapter (see Equations 2-3 
through 2-6 of PS2). For purposes of calculating the relative 
accuracy, ensure that the reference method and monitoring system 
data are on a consistent moisture basis, either wet or dry.The main 
and alternative RATA performance specifications in Table A-1 for Hg 
CEMS also apply to the sorbent trap monitoring system.
    4.1.2.5 Bias Adjustment. Measurement or adjustment of sorbent 
trap monitoring system data for bias is not required.
    4.1.3 Diluent Gas, Flow Rate, and/or Moisture Monitoring 
Systems. Monitoring systems that are used to measure stack gas 
volumetric flow rate, diluent gas concentration, or stack gas 
moisture content, either for routine operation of a sorbent trap 
monitoring system or to convert Hg concentration data to units of 
the applicable emission limit, must be certified in accordance with 
the applicable provisions of part 75 of this chapter.
    4.2 Recertification. Whenever the owner or operator makes a 
replacement, modification, or change to a certified CEMS or sorbent 
trap monitoring system that may significantly affect the ability of 
the system to accurately measure or record pollutant or diluent gas 
concentrations, stack gas flow rates, or stack gas moisture content, 
the owner or operator shall recertify the monitoring system. 
Furthermore, whenever the owner or operator makes a replacement, 
modification, or change to the flue gas handling system or the unit 
operation that may significantly change the concentration or flow 
profile, the owner or operator shall recertify the monitoring 
system. The same tests performed for the initial certification of 
the monitoring system shall be repeated for recertification, unless 
otherwise specified by the Administrator. Examples of changes that 
require recertification include: replacement of a gas analyzer; 
complete monitoring system replacement, and changing the location or 
orientation of the sampling probe.

5. Ongoing Quality Assurance (QA) and Data Validation

    5.1 Hg CEMS.
    5.1.1 Required QA Tests. Periodic QA testing of each Hg CEMS is 
required following initial certification. The required QA tests, the 
test frequencies, and the performance specifications that must be 
met are summarized in Table A-2, below. All tests must be performed 
with the affected unit(s) operating (i.e., combusting fuel). Except 
for the RATA, which must be performed at normal load, no particular 
load level is required for the tests. For each test, follow the same 
basic procedures in section 4.1.1 of this appendix that were used 
for initial certification.
    5.1.2 Test Frequency. The frequency for the required QA tests of 
the Hg CEMS shall be as follows:
    5.1.2.1 Calibration error tests of the Hg CEMS are required 
daily, except during unit outages. Use either NIST-traceable 
elemental Hg standards or NIST-traceable oxidized Hg standards for 
these calibrations. Both a zero-level gas and either a mid-level or 
high-level gas are required for these calibrations.
    5.1.2.2 Perform a linearity check of the Hg CEMS in each QA 
operating quarter, using low-level, mid-level, and high-level NIST-
traceable elemental Hg standards. For units that operate 
infrequently, limited exemptions from this test are allowed for 
``non-QA operating quarters''. A maximum of three consecutive 
exemptions for this reason are permitted, following the quarter of 
the last test. After the third consecutive exemption, a linearity 
check must be performed in the next calendar quarter or within a 
grace period of 168 unit or stack operating hours after the end of 
that quarter. The test frequency for 3-level system integrity checks 
(if performed in lieu of linearity checks) is the same as for the 
linearity checks. Use low-level, mid-level, and high-level NIST-
traceable oxidized Hg standards for the system integrity checks.
    5.1.2.3 If required, perform a single-level system integrity 
check weekly, i.e., once every 7 operating days (see the third 
column in Table A-2).
    5.1.2.4 The test frequency for the RATAs of the Hg CEMS shall be 
annual, i.e., once every four QA operating quarters. For units that 
operate infrequently, extensions of RATA deadlines are allowed for 
non-QA operating quarters. Following a RATA, if there is a 
subsequent non-QA quarter, it extends the deadline for the next test 
by one calendar quarter. However, there is a limit to these 
extensions; the deadline may not be extended beyond the end of the 
eighth calendar quarter after the quarter of the last test. At that 
point, a RATA must either be performed within the eighth calendar 
quarter or in a 720 hour unit or stack operating hour grace period 
following that quarter. When a required annual RATA is done within a 
grace period, the deadline for the next RATA is three QA operating 
quarters after the quarter in which the grace period test is 
performed.
    5.1.3 Grace Periods.
    5.1.3.1 A 168 unit or stack operating hour grace period is 
available for quarterly linearity checks and 3-level system 
integrity checks of the Hg CEMS.
    5.1.3.2 A 720 unit or stack operating hour grace period is 
available for RATAs of the Hg CEMS.
    5.1.3.3 There is no grace period for weekly system integrity 
checks. The test must be completed once every 7 operating days.
    5.1.4 Data Validation. The Hg CEMS is considered to be out-of-
control, and data from the CEMS may not be reported as quality-
assured, when any one of the acceptance criteria for the required QA 
tests in Table A-2 is not met. The CEMS is also considered to be 
out-of-control when a required QA test is not performed on schedule 
or within an allotted grace period. To end an out-of-control period, 
the QA test that was either failed or not done on time must be 
performed and passed. Out-of-control periods are counted as hours of 
monitoring system downtime.
    5.1.5 Conditional Data Validation. For certification, 
recertification, and diagnostic testing of Hg monitoring systems, 
and for the required QA tests when non-redundant backup Hg 
monitoring systems or temporary like-kind Hg analyzers are brought 
into service, the conditional data validation provisions in 
Sec. Sec.  75.20(b)(3)(ii) through (b)(3)(ix) of this chapter may be 
used to avoid or minimize data loss. The allotted window of time to 
complete 7-day calibration error tests, linearity checks, cycle time 
tests, and RATAs shall be as specified in Sec.  75.20(b)(3)(iv) of 
this chapter. Required system integrity checks must be completed 
within 168 unit or stack operating hours after the probationary 
calibration error test.

                              Table A-2--On-Going QA Test Requirements for Hg CEMS
----------------------------------------------------------------------------------------------------------------
                                                                       With these
  Perform this type of QA test . . .   At this frequency . . .     qualifications and    Acceptance criteria . .
                                                                    exceptions . . .                .
----------------------------------------------------------------------------------------------------------------
Calibration error test...............  Daily..................   Use either a    [verbarlm]R-A
                                                                 mid- or high-level gas.  [verbarlm] <= 5.0% of
                                                                                          span value.
                                                                                         or
                                                                                         [verbarlm]R-A
                                                                                          [verbarlm] <= 1.0
                                                                                          [mu]g/scm.
                                                                 Use either
                                                                 elemental or oxidized
                                                                 Hg.

[[Page 9505]]

 
                                                                 Calibrations
                                                                 are not required when
                                                                 the unit is not in
                                                                 operation.
Single-level system integrity check..  Weekly \1\.............   Required only   [verbarlm]R-Aavg
                                                                 for systems with         [verbarlm] <= 10.0% of
                                                                 converters.              the reference gas
                                                                                          value.
                                                                                         or
                                                                                         [verbarlm]R-Aavg
                                                                                          [verbarlm] <= 0.8
                                                                                          [micro]g/scm.
                                                                 Use oxidized
                                                                 Hg--either mid- or
                                                                 high-level.
                                                                 Not required
                                                                 if daily calibrations
                                                                 are done with a NIST-
                                                                 traceable source of
                                                                 oxidized Hg.
Linearity check                        Quarterly \3\..........   Required in     [verbarlm]R-Aavg
or...................................                            each ``QA operating      [verbarlm] <= 10.0% of
3-level system integrity check.......                            quarter'' 2--and no      the reference gas
                                                                 less than once every 4   value, at each
                                                                 calendar quarters.       calibration gas level.
                                                                                         or
                                                                                         [verbarlm]R-Aavg
                                                                                          [verbarlm] <= 0.8
                                                                                          [mu]g/scm.
                                                                 168 operating
                                                                 hour grace period
                                                                 available.
                                                                 Use elemental
                                                                 Hg for linearity check.
                                                                 Use oxidized
                                                                 Hg for system
                                                                 integrity check.
                                                                 For system
                                                                 integrity check, CEMS
                                                                 must have a converter.
RATA.................................  Annual \4\.............   Test deadline   20.0% RA.
                                                                 may be extended for     or
                                                                 ``non-QA operating      [verbarlm]RMavg-Cavg
                                                                 quarters'', up to a      [verbarlm] <= 1.0
                                                                 maximum of 8 quarters    [mu]g/scm,
                                                                 from the quarter of     if
                                                                 the previous test.      RMavg < 5.0 [mu]g/scm.
                                                                 720 operating
                                                                 hour grace period
                                                                 available.
----------------------------------------------------------------------------------------------------------------
\1\ ``Weekly'' means once every 7 operating days.
\2\ A ``QA operating quarter'' is a calendar quarter with at least 168 unit or stack operating hours.
\3\ ``Quarterly'' means once every QA operating quarter.
\4\ ``Annual'' means once every four QA operating quarters.

    5.1.6 Adjustment of Span. If you discover that a span adjustment 
is needed (e.g., if the Hg concentration readings exceed the span 
value for a significant percentage of the unit operating hours in a 
calendar quarter), you must implement the span adjustment within 90 
days after the end of the calendar quarter in which you identify the 
need for the adjustment. A diagnostic linearity check is required 
within 168 unit or stack operating hours after changing the span 
value.
    5.2 Sorbent Trap Monitoring Systems.
    5.2.1 Each sorbent trap monitoring system shall be continuously 
operated and maintained in accordance with Performance Specification 
(PS) 12B in appendix B to part 60 of this chapter. The QA/QC 
criteria for routine operation of the system are summarized in Table 
12B-1 of PS 12B. Each pair of sorbent traps may be used to sample 
the stack gas for up to 14 operating days.
    5.2.2 For ongoing QA, periodic RATAs of the system are required.
    5.2.2.1 The RATA frequency shall be annual, i.e., once every 
four QA operating quarters. The provisions in section 5.1.2.4 of 
this appendix pertaining to RATA deadline extensions also apply to 
sorbent trap monitoring systems.
    5.2.2.2 The same RATA performance criteria specified in Table A-
4 for Hg CEMS shall apply to the annual RATAs of the sorbent trap 
monitoring system.
    5.2.2.3 A 720 unit or stack operating hour grace period is 
available for RATAs of the monitoring system.
    5.2.3 Data validation for sorbent trap monitoring systems shall 
be done in accordance with Table 12B-1 in Performance Specification 
(PS) 12B in appendix B to part 60 of this chapter. All periods of 
invalid data shall be counted as hours of monitoring system 
downtime.
    5.3 Flow Rate, Diluent Gas, and Moisture Monitoring Systems. The 
on-going QA test requirements for these monitoring systems are 
specified in part 75 of this chapter (see Sec. Sec.  63.10010(b) 
through (d)).
    5.4 QA/QC Program Requirements. The owner or operator shall 
develop and implement a quality assurance/quality control (QA/QC) 
program for the Hg CEMS and/or sorbent trap monitoring systems that 
are used to provide data under this subpart. At a minimum, the 
program shall include a written plan that describes in detail (or 
that refers to separate documents containing) complete, step-by-step 
procedures and operations for the most important QA/QC activities. 
Electronic storage of the QA/QC plan is permissible, provided that 
the information can be made available in hard copy to auditors and 
inspectors. The QA/QC program requirements for the diluent gas, flow 
rate, and moisture monitoring systems described in section 3.2.1.3 
of this appendix are specified in section 1 of appendix B to part 75 
of this chapter.
    5.4.1 General Requirements.
    5.4.1.1 Preventive Maintenance. Keep a written record of 
procedures needed to maintain the Hg CEMS and/or sorbent trap 
monitoring system(s) in proper operating condition and a schedule 
for those procedures. Include, at a minimum, all procedures 
specified by the manufacturers of the equipment and, if applicable, 
additional or alternate procedures developed for the equipment.
    5.4.1.2 Recordkeeping and Reporting. Keep a written record 
describing procedures that will be used to implement the 
recordkeeping and reporting requirements of this appendix.
    5.4.1.3 Maintenance Records. Keep a record of all testing, 
maintenance, or repair activities performed on any Hg CEMS or 
sorbent trap monitoring system in a location and format suitable for 
inspection. A maintenance log may be used for this purpose. The 
following records should be maintained: date, time, and description 
of any testing, adjustment, repair, replacement, or preventive 
maintenance action performed on any monitoring system and records of 
any corrective actions associated with a monitor outage period. 
Additionally, any adjustment that may significantly affect a 
system's ability to accurately measure emissions data must be

[[Page 9506]]

recorded (e.g., changing the dilution ratio of a CEMS), and a 
written explanation of the procedures used to make the adjustment(s) 
shall be kept.
    5.4.2 Specific Requirements for Hg CEMS.
    5.4.2.1 Daily Calibrations, Linearity Checks and System 
Integrity Checks. Keep a written record of the procedures used for 
daily calibrations of the Hg CEMS. If moisture and/or chlorine is 
added to the Hg calibration gas, document how the dilution effect of 
the moisture and/or chlorine addition on the calibration gas 
concentration is accounted for in an appropriate manner. Also keep 
records of the procedures used to perform linearity checks of the Hg 
CEMS and the procedures for system integrity checks of the Hg CEMS. 
Document how the test results are calculated and evaluated.
    5.4.2.2 Monitoring System Adjustments. Document how each 
component of the Hg CEMS will be adjusted to provide correct 
responses to calibration gases after routine maintenance, repairs, 
or corrective actions.
    5.4.2.3 Relative Accuracy Test Audits. Keep a written record of 
procedures used for RATAs of the Hg CEMS. Indicate the reference 
methods used and document how the test results are calculated and 
evaluated.
    5.4.3 Specific Requirements for Sorbent Trap Monitoring Systems.
    5.4.3.1 Sorbent Trap Identification and Tracking. Include 
procedures for inscribing or otherwise permanently marking a unique 
identification number on each sorbent trap, for chain of custody 
purposes. Keep records of the ID of the monitoring system in which 
each sorbent trap is used, and the dates and hours of each Hg 
collection period.
    5.4.3.2 Monitoring System Integrity and Data Quality. Document 
the procedures used to perform the leak checks when a sorbent trap 
is placed in service and removed from service. Also Document the 
other QA procedures used to ensure system integrity and data 
quality, including, but not limited to, gas flow meter calibrations, 
verification of moisture removal, and ensuring air-tight pump 
operation. In addition, the QA plan must include the data acceptance 
and quality control criteria in Table 12B-1 in section 9.0 of 
Performance Specification (PS) 12B in Appendix B to part 60 of this 
chapter. All reference meters used to calibrate the gas flow meters 
(e.g., wet test meters) shall be periodically recalibrated. Annual, 
or more frequent, recalibration is recommended. If a NIST-traceable 
calibration device is used as a reference flow meter, the QA plan 
must include a protocol for ongoing maintenance and periodic 
recalibration to maintain the accuracy and NIST-traceability of the 
calibrator.
    5.4.3.3 Hg Analysis. Explain the chain of custody employed in 
packing, transporting, and analyzing the sorbent traps. Keep records 
of all Hg analyses. The analyses shall be performed in accordance 
with the procedures described in section 11.0 of Performance 
Specification (PS) 12B in Appendix B to part 60 of this chapter.
    5.4.3.4 Data Collection Period. State, and provide the rationale 
for, the minimum acceptable data collection period (e.g., one day, 
one week, etc.) for the size of sorbent trap selected for the 
monitoring. Address such factors as the Hg concentration in the 
stack gas, the capacity of the sorbent trap, and the minimum mass of 
Hg required for the analysis. Each pair of sorbent traps may be used 
to sample the stack gas for up to 14 operating days.
    5.4.3.5 Relative Accuracy Test Audit Procedures. Keep records of 
the procedures and details peculiar to the sorbent trap monitoring 
systems that are to be followed for relative accuracy test audits, 
such as sampling and analysis methods.

6. Data Reduction and Calculations

    6.1 Data Reduction.
    6.1.1 Reduce the data from Hg CEMS to hourly averages, in 
accordance with Sec.  60.13(h)(2) of this chapter.
    6.1.2 For sorbent trap monitoring systems, determine the Hg 
concentration for each data collection period and assign this 
concentration value to each operating hour in the data collection 
period.
    6.1.3 For any operating hour in which valid data are not 
obtained, either for Hg concentration or for a parameter used in the 
emissions calculations (i.e., flow rate, diluent gas concentration, 
or moisture, as applicable), do not calculate the Hg emission rate 
for that hour. For the purposes of this appendix, part 75 substitute 
data values are not considered to be valid data.
    6.1.4 Operating hours in which valid data are not obtained for 
Hg concentration are considered to be hours of monitor downtime. The 
use of substitute data for Hg concentration is not required.
    6.2 Calculation of Hg Emission Rates. Use the applicable 
calculation methods in paragraphs 6.2.1 and 6.2.2 of this section to 
convert Hg concentration values to the appropriate units of the 
emission standard.
    6.2.1 Heat Input-Based Hg Emission Rates. Calculate hourly heat 
input-based Hg emission rates, in units of lb/TBtu, according to 
sections 6.2.1.1 through 6.2.1.4 of this appendix.
    6.2.1.1 Select an appropriate emission rate equation from among 
Equations 19-1 through 19-9 in EPA Method 19 in appendix A-7 to part 
60 of this chapter.
    6.2.1.2 Calculate the Hg emission rate in lb/MMBtu, using the 
equation selected from Method 19. Multiply the Hg concentration 
value by 6.24 x 10-11 to convert it from [mu]g/scm to lb/
scf. In cases where an appropriate F-factor is not listed in Table 
19-2 of Method 19, you may use F-factors from Table 1 in section 
3.3.5 of appendix F to part 75 of this chapter, or F-factors derived 
using the procedures in section 3.3.6 of appendix to part 75 of this 
chapter. Also, for startup and shutdown hours, you may calculate the 
Hg emission rate using the applicable diluent cap value specified in 
section 3.3.4.1 of appendix F to part 75 of this chapter, provided 
that the diluent gas monitor is not out-of-control and the hourly 
average O2 concentration is above 14.0% O2 
(19.0% for an IGCC) or the hourly average CO2 
concentration is below 5.0% CO2 (1.0% for an IGCC), as 
applicable.
    6.2.1.3 Multiply the lb/MMBtu value obtained in section 6.2.1.2 
of this appendix by 106 to convert it to lb/TBtu.
    6.2.1.4 The heat input-based Hg emission rate limit in Table 2 
to this subpart must be met on a 30 boiler operating day rolling 
average basis. Use Equation 19-19 in EPA Method 19 to calculate the 
Hg emission rate for each averaging period. The term Ehj 
in Equation 19-19 must be in the units of the applicable emission 
limit. Do not include non-operating hours with zero emissions in the 
average.
    6.2.2 Electrical Output-Based Hg Emission Rates. Calculate 
electrical output-based Hg emission limits in units of lb/GWh, 
according to sections 6.2.2.1 through 6.2.2.3 of this appendix.
    6.2.2.1 Calculate the Hg mass emissions for each operating hour 
in which valid data are obtained for all parameters, using Equation 
A-2 of this section (for wet-basis measurements of Hg concentration) 
or Equation A-3 of this section (for dry-basis measurements), as 
applicable:
[GRAPHIC] [TIFF OMITTED] TR16FE12.014

Where:

Mh = Hg mass emission rate for the hour (lb/h)
K = Units conversion constant, 6.24 x 10-11 lb-scm/[mu]g-
scf,
Ch = Hourly average Hg concentration, wet basis ([mu]g/
scm)
Qh = Stack gas volumetric flow rate for the hour (scfh).
    (Note: Use unadjusted flow rate values; bias adjustment is not 
required)
[GRAPHIC] [TIFF OMITTED] TR16FE12.015

Where:

Mh = Hg mass emission rate for the hour (lb/h)
K = Units conversion constant, 6.24 x 10-11 lb-scm/[mu]g-
scf.

[[Page 9507]]

Ch = Hourly average Hg concentration, dry basis ([mu]g/
dscm).
Qh = Stack gas volumetric flow rate for the hour (scfh)
(Note: Use unadjusted flow rate values; bias adjustment is not 
required).
Bws = Moisture fraction of the stack gas, expressed as a 
decimal (equal to % H2O/100)
    6.2.2.2 Use Equation A-4 of this section to calculate the 
emission rate for each unit or stack operating hour in which valid 
data are obtained for all parameters.
[GRAPHIC] [TIFF OMITTED] TR16FE12.016

Where:

Eho = Electrical output-based Hg emission rate (lb/GWh).
Mh = Hg mass emission rate for the hour, from Equation A-
2 or A-3 of this section, as applicable (lb/h).
(MW)h = Gross electrical load for the hour, in megawatts 
(MW).
10 3 = Conversion factor from megawatts to gigawatts.
    6.2.2.3 The applicable electrical output-based Hg emission rate 
limit in Table 1 or 2 to this subpart must be met on a 30-boiler 
operating day rolling average basis. Use Equation A-5 of this 
section to calculate the Hg emission rate for each averaging period.
[GRAPHIC] [TIFF OMITTED] TR16FE12.017

Where:

Eo = Hg emission rate for the averaging period (lb/GWh).
Eho = Electrical output-based hourly Hg emission rate for 
unit or stack operating hour ``h'' in the averaging period, from 
Equation A-4 of this section (lb/GWh).
n = Number of unit or stack operating hours in the averaging period 
in which valid data were obtained for all parameters (Note: Do not 
include non-operating hours with zero emission rates in the 
average).

7. Recordkeeping and Reporting

    7.1 Recordkeeping Provisions. For the Hg CEMS and/or sorbent 
trap monitoring systems and any other necessary monitoring systems 
installed at each affected unit, the owner or operator must maintain 
a file of all measurements, data, reports, and other information 
required by this appendix in a form suitable for inspection, for 5 
years from the date of each record, in accordance with Sec.  
63.10033. The file shall contain the information in paragraphs 7.1.1 
through 7.1.10 of this section.
    7.1.1 Monitoring Plan Records. For each affected unit or group 
of units monitored at a common stack, the owner or operator shall 
prepare and maintain a monitoring plan for the Hg CEMS and/or 
sorbent trap monitoring system(s) and any other monitoring system(s) 
(i.e., flow rate, diluent gas, or moisture systems) needed for 
routine operation of a sorbent trap monitoring system or to convert 
Hg concentrations to units of the applicable emission standard. The 
monitoring plan shall contain essential information on the 
continuous monitoring systems and shall Document how the data 
derived from these systems ensure that all Hg emissions from the 
unit or stack are monitored and reported.
    7.1.1.1 Updates. Whenever the owner or operator makes a 
replacement, modification, or change in a certified continuous 
monitoring system that is used to provide data under this subpart 
(including a change in the automated data acquisition and handling 
system or the flue gas handling system) which affects information 
reported in the monitoring plan (e.g., a change to a serial number 
for a component of a monitoring system), the owner or operator shall 
update the monitoring plan.
    7.1.1.2 Contents of the Monitoring Plan. For Hg CEMS and sorbent 
trap monitoring systems, the monitoring plan shall contain the 
information in sections 7.1.1.2.1 and 7.1.1.2.2 of this appendix, as 
applicable. For stack gas flow rate, diluent gas, and moisture 
monitoring systems, the monitoring plan shall include the 
information required for those systems under Sec.  75.53 (g) of this 
chapter.
    7.1.1.2.1 Electronic. The electronic monitoring plan records 
must include the following: unit or stack ID number(s); monitoring 
location(s); the Hg monitoring methodologies used; Hg monitoring 
system information, including, but not limited to: Unique system and 
component ID numbers; the make, model, and serial number of the 
monitoring equipment; the sample acquisition method; formulas used 
to calculate Hg emissions; Hg monitor span and range information The 
electronic monitoring plan shall be evaluated and submitted using 
the Emissions Collection and Monitoring Plan System (ECMPS) Client 
Tool provided by the Clean Air Markets Division in the Office of 
Atmospheric Programs of the EPA.
    7.1.1.2.2 Hard Copy. Keep records of the following: schematics 
and/or blueprints showing the location of the Hg monitoring 
system(s) and test ports; data flow diagrams; test protocols; 
monitor span and range calculations; miscellaneous technical 
justifications.
    7.1.2 Operating Parameter Records. The owner or operator shall 
record the following information for each operating hour of each 
affected unit and also for each group of units utilizing a common 
stack, to the extent that these data are needed to convert Hg 
concentration data to the units of the emission standard. For non-
operating hours, record only the items in paragraphs 7.1.2.1 and 
7.1.2.2 of this section. If there is heat input to the unit(s), but 
no electrical load, record only the items in paragraphs 7.1.2.1, 
7.1.2.2, and (if applicable) 7.1.2.4 of this section.
    7.1.2.1 The date and hour;
    7.1.2.2 The unit or stack operating time (rounded up to the 
nearest fraction of an hour (in equal increments that can range from 
one hundredth to one quarter of an hour, at the option of the owner 
or operator);
    7.1.2.3 The hourly gross unit load (rounded to nearest MWe); and
    7.1.2.4 If applicable, the F-factor used to calculate the heat 
input-based Hg emission rate.
    7.1.3 Hg Emissions Records (Hg CEMS). For each affected unit or 
common stack using a Hg CEMS, the owner or operator shall record the 
following information for each unit or stack operating hour:
    7.1.3.1 The date and hour;
    7.1.3.2 Monitoring system and component identification codes, as 
provided in the monitoring plan, if the CEMS provides a quality-
assured value of Hg concentration for the hour;
    7.1.3.3 The hourly Hg concentration, if a quality-assured value 
is obtained for the hour ([micro]g/scm, rounded to three significant 
figures);
    7.1.3.4 A special code, indicating whether or not a quality-
assured Hg concentration is obtained for the hour. This code may be 
entered manually when a temporary like-kind replacement Hg analyzer 
is used for reporting; and
    7.1.3.5 Monitor data availability, as a percentage of unit or 
stack operating hours, calculated according to Sec.  75.32 of this 
chapter.
    7.1.4 Hg Emissions Records (Sorbent Trap Monitoring Systems). 
For each affected unit or common stack using a sorbent trap 
monitoring system, each owner or operator shall record the following 
information for the unit or stack operating hour in each data 
collection period:
    7.1.4.1 The date and hour;
    7.1.4.2 Monitoring system and component identification codes, as 
provided in the monitoring plan, if the sorbent trap

[[Page 9508]]

system provides a quality-assured value of Hg concentration for the 
hour;
    7.1.4.3 The hourly Hg concentration, if a quality-assured value 
is obtained for the hour ([micro]g/scm, rounded to three significant 
figures). Note that when a quality-assured Hg concentration value is 
obtained for a particular data collection period, that single 
concentration value is applied to each operating hour of the data 
collection period.
    7.1.4.4 A special code, indicating whether or not a quality-
assured Hg concentration is obtained for the hour;
    7.1.4.5 The average flow rate of stack gas through each sorbent 
trap (in appropriate units, e.g., liters/min, cc/min, dscm/min);
    7.1.4.6 The gas flow meter reading (in dscm, rounded to the 
nearest hundredth), at the beginning and end of the collection 
period and at least once in each unit operating hour during the 
collection period;
    7.1.4.7 The ratio of the stack gas flow rate to the sample flow 
rate, as described in section 12.2 of Performance Specification (PS) 
12B in Appendix B to part 60 of this chapter; and
    7.1.4.8 Monitor data availability, as a percentage of unit or 
stack operating hours, calculated according to Sec.  75.32 of this 
chapter.
    7.1.5 Stack Gas Volumetric Flow Rate Records.
    7.1.5.1 Hourly measurements of stack gas volumetric flow rate 
during unit operation are required for routine operation of sorbent 
trap monitoring systems, to maintain the required ratio of stack gas 
flow rate to sample flow rate (see section 8.2.2 of Performance 
Specification (PS) 12B in Appendix B to part 60 of this chapter). 
Hourly stack gas flow rate data are also needed in order to 
demonstrate compliance with electrical output-based Hg emissions 
limits, as provided in section 6.2.2 of this appendix.
    7.1.5.2 For each affected unit or common stack, if hourly 
measurements of stack gas flow rate are needed for sorbent trap 
monitoring system operation or to convert Hg concentrations to the 
units of the emission standard, use a flow rate monitor that meets 
the requirements of part 75 of this chapter to record the required 
data. You must keep hourly flow rate records, as specified in Sec.  
75.57(c)(2) of this chapter.
    7.1.6 Records of Stack Gas Moisture Content.
    7.1.6.1 Correction of hourly Hg concentration data for moisture 
is sometimes required when converting Hg concentrations to the units 
of the applicable Hg emissions limit. In particular, these 
corrections are required:
    7.1.6.1.1 For sorbent trap monitoring systems;
    7.1.6.1.2 For Hg CEMS that measure Hg concentration on a dry 
basis, when you must calculate electrical output-based Hg emission 
rates; and
    7.1.6.1.3 When using certain equations from EPA Method 19 in 
appendix A-7 to part 60 of this chapter to calculate heat input-
based Hg emission rates.
    7.1.6.2 If hourly moisture corrections are required, either use 
a fuel-specific default moisture percentage from Sec.  75.11(b)(1) 
of this chapter or a certified moisture monitoring system that meets 
the requirements of part 75 of this chapter, to record the required 
data. If you use a moisture monitoring system, you must keep hourly 
records of the stack gas moisture content, as specified in Sec.  
75.57(c)(3) of this chapter.
    7.1.7 Records of Diluent Gas (CO2 or O2) Concentration.
    7.1.7.1 When a heat input-based Hg mass emissions limit must be 
met, in units of lb/TBtu, hourly measurements of CO2 or 
O2 concentration are required to convert Hg 
concentrations to units of the standard.
    7.1.7.2 If hourly measurements of diluent gas concentration are 
needed, use a certified CO2 or O2 monitor that 
meets the requirements of part 75 of this chapter to record the 
required data. You must keep hourly CO2 or O2 
concentration records, as specified in Sec.  75.57(g) of this 
chapter.
    7.1.8 Hg Emission Rate Records. For applicable Hg emission 
limits in units of lb/TBtu or lb/GWh, record the following 
information for each affected unit or common stack:
    7.1.8.1 The date and hour;
    7.1.8.2 The hourly Hg emissions rate (lb/TBtu or lb/GWh, as 
applicable, calculated according to section 6.2.1 or 6.2.2 of this 
appendix, rounded to three significant figures), if valid values of 
Hg concentration and all other required parameters (stack gas 
volumetric flow rate, diluent gas concentration, electrical load, 
and moisture data, as applicable) are obtained for the hour;
    7.1.8.3 An identification code for the formula (either the 
selected equation from Method 19 in section 6.2.1 of this appendix 
or Equation A-4 in section 6.2.2 of this appendix) used to derive 
the hourly Hg emission rate from Hg concentration, flow rate, 
electrical load, diluent gas concentration, and moisture data (as 
applicable); and
    7.1.8.4 A code indicating that the Hg emission rate was not 
calculated for the hour, if valid data for Hg concentration and/or 
any of the other necessary parameters are not obtained for the hour. 
For the purposes of this appendix, the substitute data values 
required under part 75 of this chapter for diluent gas 
concentration, stack gas flow rate and moisture content are not 
considered to be valid data.
    7.1.9 Certification and Quality Assurance Test Records. For any 
Hg CEMS and sorbent trap monitoring systems used to provide data 
under this subpart, record the following certification and quality-
assurance information:
    7.1.9.1 The reference values, monitor responses, and calculated 
calibration error (CE) values, and a flag to indicate whether the 
test was done using elemental or oxidized Hg, for all required 7-day 
calibration error tests and daily calibration error tests of the Hg 
CEMS;
    7.1.9.2 The reference values, monitor responses, and calculated 
linearity error (LE) or system integrity error (SIE) values for all 
linearity checks of the Hg CEMS, and for all single-level and 3-
level system integrity checks of the Hg CEMS;
    7.1.9.3 The CEMS and reference method readings for each test run 
and the calculated relative accuracy results for all RATAs of the Hg 
CEMS and/or sorbent trap monitoring systems;
    7.1.9.4 The stable stack gas and calibration gas readings and 
the calculated results for the upscale and downscale stages of all 
required cycle time tests of the Hg CEMS or, for a batch sampling Hg 
CEMS, the interval between measured Hg concentration readings;
    7.1.9.5 Supporting information for all required RATAs of the Hg 
monitoring systems, including records of the test dates, the raw 
reference method and monitoring system data, the results of sample 
analyses to substantiate the reported test results, and records of 
sampling equipment calibrations;
    7.1.9.6 For sorbent trap monitoring systems, also keep records 
of the results of all analyses of the sorbent traps used for routine 
daily operation of the system, and information documenting the 
results of all leak checks and the other applicable quality control 
procedures described in Table 12B-1 of Performance Specification 
(PS) 12B in appendix B to part 60 of this chapter.
    7.1.9.7 For stack gas flow rate, diluent gas, and (if 
applicable) moisture monitoring systems, you must keep records of 
all certification, recertification, diagnostic, and on-going 
quality-assurance tests of these systems, as specified in Sec.  
75.59 of this chapter.
    7.2 Reporting Requirements.
    7.2.1 General Reporting Provisions. The owner or operator shall 
comply with the following requirements for reporting Hg emissions 
from each affected unit (or group of units monitored at a common 
stack) under this subpart:
    7.2.1.1 Notifications, in accordance with paragraph 7.2.2 of 
this section;
    7.2.1.2 Monitoring plan reporting, in accordance with paragraph 
7.2.3 of this section;
    7.2.1.3 Certification, recertification, and QA test submittals, 
in accordance with paragraph 7.2.4 of this section; and
    7.2.1.4 Electronic quarterly report submittals, in accordance 
with paragraph 7.2.5 of this section.
    7.2.2 Notifications. The owner or operator shall provide 
notifications for each affected unit (or group of units monitored at 
a common stack) under this subpart in accordance with Sec.  
63.10030.
    7.2.3 Monitoring Plan Reporting. For each affected unit (or 
group of units monitored at a common stack) under this subpart using 
Hg CEMS or sorbent trap monitoring system to measure Hg emissions, 
the owner or operator shall make electronic and hard copy monitoring 
plan submittals as follows:
    7.2.3.1 Submit the electronic and hard copy information in 
section 7.1.1.2 of this appendix pertaining to the Hg monitoring 
systems at least 21 days prior to the applicable date in Sec.  
63.9984. Also submit the monitoring plan information in Sec.  
75.53.(g) pertaining to the flow rate, diluent gas, and moisture 
monitoring systems within that same time frame, if the required 
records are not already in place.
    7.2.3.2 Whenever an update of the monitoring plan is required, 
as provided in paragraph 7.1.1.1 of this section. An electronic 
monitoring plan information

[[Page 9509]]

update must be submitted either prior to or concurrent with the 
quarterly report for the calendar quarter in which the update is 
required.
    7.2.3.3 All electronic monitoring plan submittals and updates 
shall be made to the Administrator using the ECMPS Client Tool. Hard 
copy portions of the monitoring plan shall be kept on record 
according to section 7.1 of this appendix.
    7.2.4 Certification, Recertification, and Quality-Assurance Test 
Reporting. Except for daily QA tests of the required monitoring 
systems (i.e., calibration error tests and flow monitor interference 
checks), the results of all required certification, recertification, 
and quality-assurance tests described in paragraphs 7.1.10.1 through 
7.1.10.7 of this section (except for test results previously 
submitted, e.g., under the ARP) shall be submitted electronically, 
using the ECMPS Client Tool, either prior to or concurrent with the 
relevant quarterly electronic emissions report.
    7.2.5 Quarterly Reports.
    7.2.5.1 Beginning with the report for the calendar quarter in 
which the initial compliance demonstration is completed or the 
calendar quarter containing the applicable date in Sec.  63.9984, 
the owner or operator of any affected unit shall use the ECMPS 
Client Tool to submit electronic quarterly reports to the 
Administrator, in an XML format specified by the Administrator, for 
each affected unit (or group of units monitored at a common stack) 
under this subpart.
    7.2.5.2 The electronic reports must be submitted within 30 days 
following the end of each calendar quarter, except for units that 
have been placed in long-term cold storage.
    7.2.5.3 Each electronic quarterly report shall include the 
following information:
    7.2.5.3.1 The date of report generation;
    7.2.5.3.2 Facility identification information;
    7.2.5.3.3 The information in paragraphs 7.1.2 through 7.1.8 of 
this section, as applicable to the Hg emission measurement 
methodology (or methodologies) used and the units of the Hg emission 
standard(s); and
    7.2.5.3.4 The results of all daily calibration error tests of 
the Hg CEMS, as described in paragraph 7.1.90.1 of this section and 
(if applicable) the results of all daily flow monitor interference 
checks.
    7.2.5.4 Compliance Certification. Based on reasonable inquiry of 
those persons with primary responsibility for ensuring that all Hg 
emissions from the affected unit(s) under this subpart have been 
correctly and fully monitored, the owner or operator shall submit a 
compliance certification in support of each electronic quarterly 
emissions monitoring report. The compliance certification shall 
include a statement by a responsible official with that official's 
name, title, and signature, certifying that, to the best of his or 
her knowledge, the report is true, accurate, and complete.

Appendix B to Subpart UUUUU---HCl and HF Monitoring Provisions

1. Applicability

    These monitoring provisions apply to the measurement of HCl and/
or HF emissions from electric utility steam generating units, using 
CEMS. The CEMS must be capable of measuring HCl and/or HF in the 
appropriate units of the applicable emissions standard (e.g., lb/
MMBtu, lb/MWh, or lb/GWh).

2. Monitoring of HCl and/or HF Emissions

    2.1 Monitoring System Installation Requirements. Install HCl 
and/or HF CEMS and any additional monitoring systems needed to 
convert pollutant concentrations to units of the applicable 
emissions limit in accordance with Performance Specification 15 for 
extractive Fourier Transform Infrared Spectroscopy (FTIR) continuous 
emissions monitoring systems in appendix B to part 60 of this 
chapter and Sec.  63.10010(a).
    2.2 Primary and Backup Monitoring Systems. The provisions 
pertaining to primary and redundant backup monitoring systems in 
section 2.2 of appendix A to this subpart apply to HCl and HF CEMS 
and any additional monitoring systems needed to convert pollutant 
concentrations to units of the applicable emissions limit.
    2.3 FTIR Monitoring System Equipment, Supplies, Definitions, and 
General Operation. The provisions of Performance Specification 15 
Sections 2.0, 3.0, 4.0, 5.0, 6.0, and 10.0 apply.

3. Initial Certification Procedures

    The initial certification procedures for the HCl or HF CEMS used 
to provide data under this subpart are as follows:
    3.1 The HCl and/or HF CEMS must be certified according to 
Performance Specification 15 using the procedures for gas auditing 
and comparison to a reference method (RM) as specified in sections 
3.1.1 and 3.1.2 below. (Please Note: EPA plans to publish a 
technology neutral performance specification and appropriate on-
going quality-assurance requirements for HCl CEMS in the near future 
along with amendments to this appendix to accommodate their use.)
    3.1.1 You must conduct a gas audit of the HCl and/or HF CEMS as 
described in section 9.1 of Performance Specification 15, with the 
exceptions listed in sections 3.1.2.1 and 3.1.2.2 below.
    3.1.1.1 The audit sample gas does not have to be obtained from 
the Administrator; however, it must be (1) from a secondary source 
of certified gases (i.e., independent of any calibration gas used 
for the daily calibration assessments) and (2) directly traceable to 
National Institute of Standards and Technology (NIST) or VSL Dutch 
Metrology Institute (VSL) reference materials through an unbroken 
chain of comparisons. If audit gas traceable to NIST or VSL 
reference materials is not available, you may use a gas with a 
concentration certified to a specified uncertainty by the gas 
manufacturer.
    3.1.1.2 Analyze the results of the gas audit using the 
calculations in section 12.1 of Performance Specification 15. The 
calculated correction factor (CF) from Eq. 6 of Performance 
Specification 15 must be between 0.85 and 1.15. You do not have to 
test the bias for statistical significance.
    3.1.2 You must perform a relative accuracy test audit or RATA 
according to section 11.1.1.4 of Performance Specification 15 and 
the requirements below. Perform the RATA of the HCl or HF CEMS at 
normal load. Acceptable HCl/HF reference methods (RM) are Methods 26 
and 26A in appendix A-8 to part 60 of this chapter, Method 320 in 
Appendix A to this part, or ASTM D6348-03 (Reapproved 2010) 
``Standard Test Method for Determination of Gaseous Compounds by 
Extractive Direct Interface Fourier Transform Infrared (FTIR) 
Spectroscopy'' (incorporated by reference, see Sec.  63.14), each 
applied based on the criteria set forth in Table 5 of this subpart.
    3.1.2.1 When ASTM D6348-03 is used as the RM, the following 
conditions must be met:
    3.1.2.1.1 The test plan preparation and implementation in the 
Annexes to ASTM D6348-03, Sections A1 through A8 are mandatory;
    3.1.2.1.2 In ASTM D6348-03 Annex A5 (Analyte Spiking Technique), 
the percent (%) R must be determined for each target analyte (see 
Equation A5.5);
    3.1.2.1.3 For the ASTM D6348-03 test data to be acceptable for a 
target analyte, %R must be 70% >= R <= 130%; and
    3.1.2.1.4 The %R value for each compound must be reported in the 
test report and all field measurements corrected with the calculated 
%R value for that compound using the following equation:
[GRAPHIC] [TIFF OMITTED] TR16FE12.018

    3.1.2.2 The relative accuracy (RA) of the HCl or HF CEMS must be 
no greater than 20 percent of the mean value of the RM test data in 
units of ppm on the same moisture basis. Alternatively, if the mean 
RM value is less than 1.0 ppm, the RA results are acceptable if the 
absolute value of the difference between the mean RM and CEMS values 
does not exceed 0.20 ppm.
    3.2 Any additional stack gas flow rate, diluent gas, and 
moisture monitoring system(s) needed to express pollutant 
concentrations in units of the applicable emissions limit must be 
certified according to part 75 of this chapter.

[[Page 9510]]

4. Recertification Procedures

    Whenever the owner or operator makes a replacement, 
modification, or change to a certified CEMS that may significantly 
affect the ability of the system to accurately measure or record 
pollutant or diluent gas concentrations, stack gas flow rates, or 
stack gas moisture content, the owner or operator shall recertify 
the monitoring system. Furthermore, whenever the owner or operator 
makes a replacement, modification, or change to the flue gas 
handling system or the unit operation that may significantly change 
the concentration or flow profile, the owner or operator shall 
recertify the monitoring system. The same tests performed for the 
initial certification of the monitoring system shall be repeated for 
recertification, unless otherwise specified by the Administrator. 
Examples of changes that require recertification include: 
Replacement of a gas analyzer; complete monitoring system 
replacement, and changing the location or orientation of the 
sampling probe.

5. On-Going Quality Assurance Requirements

    5.1 For on-going QA test requirements for HCl and HF CEMS, 
implement the quality assurance/quality control procedures of 
Performance Specification 15 of appendix B to part 60 of this 
chapter as set forth in sections 5.1.1 through 5.1.3 and 5.3.2 of 
this appendix.
    5.1.1 On a daily basis, you must assess the calibration error of 
the HCl or HF CEMS using either a calibration transfer standard as 
specified in Performance Specification 15 Section 10.1 which 
references Section 4.5 of the FTIR Protocol or a HCl and/or HF 
calibration gas at a concentration no greater than two times the 
level corresponding to the applicable emission limit. A calibration 
transfer standard is a substitute calibration compound chosen to 
ensure that the FTIR is performing well at the wavelength regions 
used for analysis of the target analytes. The measured concentration 
of the calibration transfer standard or HCl and/or HF calibration 
gas results must agree within  5 percent of the 
reference gas value after correction for differences in pressure.
    5.1.2 On a quarterly basis, you must conduct a gas audit of the 
HCl and/or HF CEMS as described in section 3.1.1 of this appendix. 
For the purposes of this appendix, ``quarterly'' means once every 
``QA operating quarter'' (as defined in section 3.1.20 of appendix A 
to this subpart). You have the option to use HCl gas in lieu of HF 
gas for conducting this audit on an HF CEMS. To the extent 
practicable, perform consecutive quarterly gas audits at least 30 
days apart. The initial quarterly audit is due in the first QA 
operating quarter following the calendar quarter in which 
certification testing of the CEMS is successfully completed. Up to 
three consecutive exemptions from the quarterly audit requirement 
are allowed for ``non-QA operating quarters'' (i.e., calendar 
quarters in which there are less than 168 unit or stack operating 
hours). However, no more than four consecutive calendar quarters may 
elapse without performing a gas audit, except as otherwise provided 
in section 5.3.3.2.1 of this appendix.
    5.1.3 You must perform an annual relative accuracy test audit or 
RATA of the HCl or HF CEMS as described in section 3.1.2 of this 
appendix. Perform the RATA at normal load. For the purposes of this 
appendix, ``annual'' means once every four ``QA operating quarters'' 
(as defined in section 3.1.20 of appendix A to this subpart). The 
first annual RATA is due within four QA operating quarters following 
the calendar quarter in which the initial certification testing of 
the HCl or HF CEMS is successfully completed. The provisions in 
section 5.1.2.4 of appendix A to this subpart pertaining to RATA 
deadline extensions also apply.
    5.2 Stack gas flow rate, diluent gas, and moisture monitoring 
systems must meet the applicable on-going QA test requirements of 
part 75 of this chapter.
    5.3 Data Validation.
    5.3.1 Out-of-Control Periods. A HCl or HF CEMS that is used to 
provide data under this appendix is considered to be out-of-control, 
and data from the CEMS may not be reported as quality-assured, when 
any acceptance criteria for a required QA test is not met. The HCl 
or HF CEMS is also considered to be out-of-control when a required 
QA test is not performed on schedule or within an allotted grace 
period. To end an out-of-control period, the QA test that was either 
failed or not done on time must be performed and passed. Out-of-
control periods are counted as hours of monitoring system downtime.
    5.3.2 Grace Periods. For the purposes of this appendix, a 
``grace period'' is defined as a specified number of unit or stack 
operating hours after the deadline for a required quality-assurance 
test of a continuous monitor has passed, in which the test may be 
performed and passed without loss of data.
    5.3.2.1 For the flow rate, diluent gas, and moisture monitoring 
systems described in section 5.2 of this appendix, a 168 unit or 
stack operating hour grace period is available for quarterly 
linearity checks, and a 720 unit or stack operating hour grace 
period is available for RATAs, as provided, respectively, in 
sections 2.2.4 and 2.3.3 of appendix B to part 75 of this chapter.
    5.3.2.2 For the purposes of this appendix, if the deadline for a 
required gas audit or RATA of a HCl or HF CEMS cannot be met due to 
circumstances beyond the control of the owner or operator:
    5.3.2.2.1 A 168 unit or stack operating hour grace period is 
available in which to perform the gas audit; or
    5.3.2.2.2 A 720 unit or stack operating hour grace period is 
available in which to perform the RATA.
    5.3.2.3 If a required QA test is performed during a grace 
period, the deadline for the next test shall be determined as 
follows:
    5.3.2.3.1 For a gas audit or RATA of the monitoring systems 
described in section 5.1 of this appendix, determine the deadline 
for the next gas audit or RATA (as applicable) in accordance with 
section 2.2.4(b) or 2.3.3(d) of appendix B to part 75 of this 
chapter; treat a gas audit in the same manner as a linearity check.
    5.3.2.3.2 For the gas audit of a HCl or HF CEMS, the grace 
period test only satisfies the audit requirement for the calendar 
quarter in which the test was originally due. If the calendar 
quarter in which the grace period audit is performed is a QA 
operating quarter, an additional gas audit is required for that 
quarter.
    5.3.2.3.3 For the RATA of a HCl or HF CEMS, the next RATA is due 
within three QA operating quarters after the calendar quarter in 
which the grace period test is performed.
    5.3.4 Conditional Data Validation. For recertification and 
diagnostic testing of the monitoring systems that are used to 
provide data under this appendix, and for the required QA tests when 
non-redundant backup monitoring systems or temporary like-kind 
replacement analyzers are brought into service, the conditional data 
validation provisions in Sec. Sec.  75.20(b)(3)(ii) through 
(b)(3)(ix) of this chapter may be used to avoid or minimize data 
loss. The allotted window of time to complete calibration tests and 
RATAs shall be as specified in Sec.  75.20(b)(3)(iv) of this 
chapter; the allotted window of time to complete a gas audit shall 
be the same as for a linearity check (i.e., 168 unit or stack 
operating hours).

6. Missing Data Requirements

    For the purposes of this appendix, the owner or operator of an 
affected unit shall not substitute for missing data from HCl or HF 
CEMS. Any process operating hour for which quality-assured HCl or HF 
concentration data are not obtained is counted as an hour of 
monitoring system downtime.

7. Bias Adjustment

    Bias adjustment of hourly emissions data from a HCl or HF CEMS 
is not required.

8. QA/QC Program Requirements

    The owner or operator shall develop and implement a quality 
assurance/quality control (QA/QC) program for the HCl and/or HF CEMS 
that are used to provide data under this subpart. At a minimum, the 
program shall include a written plan that describes in detail (or 
that refers to separate documents containing) complete, step-by-step 
procedures and operations for the most important QA/QC activities. 
Electronic storage of the QA/QC plan is permissible, provided that 
the information can be made available in hard copy to auditors and 
inspectors. The QA/QC program requirements for the other monitoring 
systems described in section 5.2 of this appendix are specified in 
section 1 of appendix B to part 75 of this chapter.
    8.1 General Requirements for HCl and HF CEMS.
    8.1.1 Preventive Maintenance. Keep a written record of 
procedures needed to maintain the HCl and/or HF CEMS in proper 
operating condition and a schedule for those procedures. This shall, 
at a minimum, include procedures specified by the manufacturers of 
the equipment and, if applicable, additional or alternate procedures 
developed for the equipment.
    8.1.2 Recordkeeping and Reporting. Keep a written record 
describing procedures that will be used to implement the 
recordkeeping and reporting requirements of this appendix.
    8.1.3 Maintenance Records. Keep a record of all testing, 
maintenance, or repair

[[Page 9511]]

activities performed on any HCl or HF CEMS in a location and format 
suitable for inspection. A maintenance log may be used for this 
purpose. The following records should be maintained: Date, time, and 
description of any testing, adjustment, repair, replacement, or 
preventive maintenance action performed on any monitoring system and 
records of any corrective actions associated with a monitor outage 
period. Additionally, any adjustment that may significantly affect a 
system's ability to accurately measure emissions data must be 
recorded and a written explanation of the procedures used to make 
the adjustment(s) shall be kept.
    8.2 Specific Requirements for HCl and HF CEMS. The following 
requirements are specific to HCl and HF CEMS:
    8.2.1 Keep a written record of the procedures used for each type 
of QA test required for each HCl and HF CEMS. Explain how the 
results of each type of QA test are calculated and evaluated.
    8.2.2 Explain how each component of the HCl and/or HF CEMS will 
be adjusted to provide correct responses to calibration gases after 
routine maintenance, repairs, or corrective actions.

9. Data Reduction and Calculations

    9.1 Design and operate the HCl and/or HF CEMS to complete a 
minimum of one cycle of operation (sampling, analyzing, and data 
recording) for each successive 15-minute period.
    9.2 Reduce the HCl and/or HF concentration data to hourly 
averages in accordance with Sec.  60.13(h)(2) of this chapter.
    9.3 Convert each hourly average HCl or HF concentration to an 
HCl or HF emission rate expressed in units of the applicable 
emissions limit.
    9.3.1 For heat input-based emission rates, select an appropriate 
emission rate equation from among Equations 19-1 through 19-9 in EPA 
Method 19 in appendix A-7 to part 60 of this chapter, to calculate 
the HCl or HF emission rate in lb/MMBtu. Multiply the HCl 
concentration value (ppm) by 9.43 x 10-8 to convert it to 
lb/scf, for use in the applicable Method 19 equation. For HF, the 
conversion constant from ppm to lb/scf is 5.18 x 10-8.
    9.3.2 For electrical output-based emission rates, first 
calculate the HCl or HF mass emission rate (lb/h), using an equation 
that has the general form of Equation A-2 or A-3 in appendix A to 
this subpart (as applicable), replacing the value of K with 9.43 x 
10-8 lb/scf-ppm (for HCl) or 5.18 x 10-8 (for 
HF) and defining Ch as the hourly average HCl or HF 
concentration in ppm. Then, use Equation A-4 in appendix A to this 
subpart to calculate the HCl or HF emission rate in lb/GWh. If the 
applicable HCl or HF limit is expressed in lb/MWh, divide the result 
from Equation A-4 by 103.
    9.4 Use Equation A-5 in appendix A of this subpart to calculate 
the required 30 operating day rolling average HCl or HF emission 
rates. Round off each 30 operating day average to two significant 
figures. The term Eho in Equation A-5 must be in the 
units of the applicable emissions limit.

10. Recordkeeping Requirements

    10.1 For each HCl or HF CEMS installed at an affected source, 
and for any other monitoring system(s) needed to convert pollutant 
concentrations to units of the applicable emissions limit, the owner 
or operator must maintain a file of all measurements, data, reports, 
and other information required by this appendix in a form suitable 
for inspection, for 5 years from the date of each record, in 
accordance with Sec.  63.10033. The file shall contain the 
information in paragraphs 10.1.1 through 10.1.8 of this section.
    10.1.1 Monitoring Plan Records. For each affected unit or group 
of units monitored at a common stack, the owner or operator shall 
prepare and maintain a monitoring plan for the HCl and/or HF CEMS 
and any other monitoring system(s) (i.e, flow rate, diluent gas, or 
moisture systems) needed to convert pollutant concentrations to 
units of the applicable emission standard. The monitoring plan shall 
contain essential information on the continuous monitoring systems 
and shall explain how the data derived from these systems ensure 
that all HCl or HF emissions from the unit or stack are monitored 
and reported.
    10.1.1.1 Updates. Whenever the owner or operator makes a 
replacement, modification, or change in a certified continuous HCl 
or HF monitoring system that is used to provide data under this 
subpart (including a change in the automated data acquisition and 
handling system or the flue gas handling system) which affects 
information reported in the monitoring plan (e.g., a change to a 
serial number for a component of a monitoring system), the owner or 
operator shall update the monitoring plan.
    10.1.1.2 Contents of the Monitoring Plan. For HCl and/or HF 
CEMS, the monitoring plan shall contain the applicable electronic 
and hard copy information in sections 10.1.1.2.1 and 10.1.1.2.2 of 
this appendix. For stack gas flow rate, diluent gas, and moisture 
monitoring systems, the monitoring plan shall include the electronic 
and hard copy information required for those systems under Sec.  
75.53 (g) of this chapter. The electronic monitoring plan shall be 
evaluated using the ECMPS Client Tool.
    10.1.1.2.1 Electronic. Record the unit or stack ID number(s); 
monitoring location(s); the HCl or HF monitoring methodology used 
(i.e., CEMS); HCl or HF monitoring system information, including, 
but not limited to: unique system and component ID numbers; the 
make, model, and serial number of the monitoring equipment; the 
sample acquisition method; formulas used to calculate emissions; 
monitor span and range information (if applicable).
    10.1.1.2.2 Hard Copy. Keep records of the following: schematics 
and/or blueprints showing the location of the monitoring system(s) 
and test ports; data flow diagrams; test protocols; monitor span and 
range calculations (if applicable); miscellaneous technical 
justifications.
    10.1.2 Operating Parameter Records. For the purposes of this 
appendix, the owner or operator shall record the following 
information for each operating hour of each affected unit or group 
of units utilizing a common stack, to the extent that these data are 
needed to convert pollutant concentration data to the units of the 
emission standard. For non-operating hours, record only the items in 
paragraphs 10.1.2.1 and 10.1.2.2 of this section. If there is heat 
input to the unit(s), but no electrical load, record only the items 
in paragraphs 10.1.2.1, 10.1.2.2, and (if applicable) 10.1.2.4 of 
this section.
    10.1.2.1 The date and hour;
    10.1.2.2 The unit or stack operating time (rounded up to the 
nearest fraction of an hour (in equal increments that can range from 
one hundredth to one quarter of an hour, at the option of the owner 
or operator);
    10.1.2.3 The hourly gross unit load (rounded to nearest MWge); 
and
    10.1.2.4 If applicable, the F-factor used to calculate the heat 
input-based pollutant emission rate.
    10.1.3 HCl and/or HF Emissions Records. For HCl and/or HF CEMS, 
the owner or operator must record the following information for each 
unit or stack operating hour:
    10.1.3.1 The date and hour;
    10.1.3.2 Monitoring system and component identification codes, 
as provided in the electronic monitoring plan, for each hour in 
which the CEMS provides a quality-assured value of HCl or HF 
concentration (as applicable);
    10.1.3.3 The pollutant concentration, for each hour in which a 
quality-assured value is obtained. For HCl and HF, record the data 
in parts per million (ppm), rounded to three significant figures.
    10.1.3.4 A special code, indicating whether or not a quality-
assured HCl or HF concentration value is obtained for the hour. This 
code may be entered manually when a temporary like-kind replacement 
HCl or HF analyzer is used for reporting; and
    10.1.3.5 Monitor data availability, as a percentage of unit or 
stack operating hours, calculated according to Sec.  75.32 of this 
chapter.
    10.1.4 Stack Gas Volumetric Flow Rate Records.
    10.1.4.1 Hourly measurements of stack gas volumetric flow rate 
during unit operation are required to demonstrate compliance with 
electrical output-based HCl or HF emissions limits (i.e., lb/MWh or 
lb/GWh).
    10.1.4.2 Use a flow rate monitor that meets the requirements of 
part 75 of this chapter to record the required data. You must keep 
hourly flow rate records, as specified in Sec.  75.57(c)(2) of this 
chapter.
    10.1.5 Records of Stack Gas Moisture Content.
    10.1.5.1 Correction of hourly pollutant concentration data for 
moisture is sometimes required when converting concentrations to the 
units of the applicable Hg emissions limit. In particular, these 
corrections are required:
    10.1.5.1.1 To calculate electrical output-based pollutant 
emission rates, when using a CEMS that measures pollutant 
concentrations on a dry basis; and
    10.1.5.1.2 To calculate heat input-based pollutant emission 
rates, when using certain equations from EPA Method 19 in appendix 
A-7 to part 60 of this chapter.

[[Page 9512]]

    10.1.5.2 If hourly moisture corrections are required, either use 
a fuel-specific default moisture percentage for coal-fired units 
from Sec.  75.11(b)(1) of this chapter, an Administrator approved 
default moisture value for non-coal-fired units (as per paragraph 
63.10010(d) of this subpart), or a certified moisture monitoring 
system that meets the requirements of part 75 of this chapter, to 
record the required data. If you elect to use a moisture monitoring 
system, you must keep hourly records of the stack gas moisture 
content, as specified in Sec.  75.57(c)(3) of this chapter.
    10.1.6 Records of Diluent Gas (CO2 or O2) 
Concentration.
    10.1.6.1 To assess compliance with a heat input-based HCl or HF 
emission rate limit in units of lb/MMBtu, hourly measurements of 
CO2 or O2 concentration are required to 
convert pollutant concentrations to units of the standard.
    10.1.6.2 If hourly measurements of diluent gas concentration are 
needed, you must use a certified CO2 or O2 
monitor that meets the requirements of part 75 of this chapter to 
record the required data. For all diluent gas monitors, you must 
keep hourly CO2 or O2 concentration records, 
as specified in Sec.  75.57(g) of this chapter.
    10.1.7 HCl and HF Emission Rate Records. For applicable HCl and 
HF emission limits in units of lb/MMBtu, lb/MWh, or lb/GWh, record 
the following information for each affected unit or common stack:
    10.1.7.1 The date and hour;
    10.1.7.2 The hourly HCl and/or HF emissions rate (lb/MMBtu, lb/
MWh, or lb/GWh, as applicable, rounded to three significant 
figures), for each hour in which valid values of HCl or HF 
concentration and all other required parameters (stack gas 
volumetric flow rate, diluent gas concentration, electrical load, 
and moisture data, as applicable) are obtained for the hour;
    10.1.7.3 An identification code for the formula used to derive 
the hourly HCl or HF emission rate from HCl or HF concentration, 
flow rate, electrical load, diluent gas concentration, and moisture 
data (as applicable); and
    10.1.7.4 A code indicating that the HCl or HF emission rate was 
not calculated for the hour, if valid data for HCl or HF 
concentration and/or any of the other necessary parameters are not 
obtained for the hour. For the purposes of this appendix, the 
substitute data values required under part 75 of this chapter for 
diluent gas concentration, stack gas flow rate and moisture content 
are not considered to be valid data.
    10.1.8 Certification and Quality Assurance Test Records. For the 
HCl and/or HF CEMS used to provide data under this subpart at each 
affected unit (or group of units monitored at a common stack), 
record the following information for all required certification, 
recertification, diagnostic, and quality-assurance tests:
    10.1.8.1 HCl and HF CEMS.
    10.1.8.1.1 For all required daily calibrations (including 
calibration transfer standard tests) of the HCl or HF CEMS, record 
the test dates and times, reference values, monitor responses, and 
calculated calibration error values;
    10.1.8.1.2 For gas audits of HCl or HF CEMS, record the date and 
time of each spiked and unspiked sample, the audit gas reference 
values and uncertainties. Keep records of all calculations and data 
analyses required under sections 9.1 and 12.1 of Performance 
Specification 15, and the results of those calculations and 
analyses.
    10.1.8.1.3 For each RATA of a HCl or HF CEMS, record the date 
and time of each test run, the reference method(s) used, and the 
reference method and HCl or HF CEMS values. Keep records of the data 
analyses and calculations used to determine the relative accuracy.
    10.1.8.2 Additional Monitoring Systems. For the stack gas flow 
rate, diluent gas, and moisture monitoring systems described in 
section 3.2 of this appendix, you must keep records of all 
certification, recertification, diagnostic, and on-going quality-
assurance tests of these systems, as specified in Sec.  75.59(a) of 
this chapter.

11. Reporting Requirements

    11.1 General Reporting Provisions. The owner or operator shall 
comply with the following requirements for reporting HCl and/or HF 
emissions from each affected unit (or group of units monitored at a 
common stack):
    11.1.1 Notifications, in accordance with paragraph 11.2 of this 
section;
    11.1.2 Monitoring plan reporting, in accordance with paragraph 
11.3 of this section;
    11.1.3 Certification, recertification, and QA test submittals, 
in accordance with paragraph 11.4 of this section; and
    11.1.4 Electronic quarterly report submittals, in accordance 
with paragraph 11.5 of this section.
    11.2 Notifications. The owner or operator shall provide 
notifications for each affected unit (or group of units monitored at 
a common stack) in accordance with Sec.  63.10030.
    11.3 Monitoring Plan Reporting. For each affected unit (or group 
of units monitored at a common stack) using HCl and/or HF CEMS, the 
owner or operator shall make electronic and hard copy monitoring 
plan submittals as follows:
    11.3.1 Submit the electronic and hard copy information in 
section 10.1.1.2 of this appendix pertaining to the HCl and/or HF 
monitoring systems at least 21 days prior to the applicable date in 
Sec.  63.9984. Also, if applicable, submit monitoring plan 
information pertaining to any required flow rate, diluent gas, and/
or moisture monitoring systems within that same time frame, if the 
required records are not already in place.
    11.3.2 Update the monitoring plan when required, as provided in 
paragraph 10.1.1.1 of this appendix. An electronic monitoring plan 
information update must be submitted either prior to or concurrent 
with the quarterly report for the calendar quarter in which the 
update is required.
    11.3.3 All electronic monitoring plan submittals and updates 
shall be made to the Administrator using the ECMPS Client Tool. Hard 
copy portions of the monitoring plan shall be kept on record 
according to section 10.1 of this appendix.
    11.4 Certification, Recertification, and Quality-Assurance Test 
Reporting Requirements. Except for daily QA tests (i.e., 
calibrations and flow monitor interference checks), which are 
included in each electronic quarterly emissions report, use the 
ECMPS Client Tool to submit the results of all required 
certification, recertification, quality-assurance, and diagnostic 
tests of the monitoring systems required under this appendix 
electronically, either prior to or concurrent with the relevant 
quarterly electronic emissions report.
    11.4.1 For daily calibrations (including calibration transfer 
standard tests), report the information in Sec.  75.59(a)(1) of this 
chapter, excluding paragraphs (a)(1)(ix) through (a)(1)(xi).
    11.4.2 For each quarterly gas audit of a HCl or HF CEMS, report:
    11.4.2.1 Facility ID information;
    11.4.2.2 Monitoring system ID number;
    11.4.2.3 Type of test (e.g., quarterly gas audit);
    11.4.2.4 Reason for test;
    11.4.2.5 Certified audit (spike) gas concentration value (ppm);
    11.4.2.6 Measured value of audit (spike) gas, including date and 
time of injection;
    11.4.2.7 Calculated dilution ratio for audit (spike) gas;
    11.4.2.8 Date and time of each spiked flue gas sample;
    11.4.2.9 Date and time of each unspiked flue gas sample;
    11.4.2.10 The measured values for each spiked gas and unspiked 
flue gas sample (ppm);
    11.4.2.11 The mean values of the spiked and unspiked sample 
concentrations and the expected value of the spiked concentration as 
specified in section 12.1 of Performance Specification 15 (ppm);
    11.4.2.12 Bias at the spike level as calculated using equation 3 
in section 12.1 of Performance Specification 15; and
    11.4.2.13 The correction factor (CF), calculated using equation 
6 in section 12.1 of Performance Specification 15.
    11.4.3 For each RATA of a HCl or HF CEMS, report:
    11.4.3.1 Facility ID information;
    11.4.3.2 Monitoring system ID number;
    11.4.3.3 Type of test (i.e., initial or annual RATA);
    11.4.3.4 Reason for test;
    11.4.3.5 The reference method used;
    11.4.3.6 Starting and ending date and time for each test run;
    11.4.3.7 Units of measure;
    11.4.3.8 The measured reference method and CEMS values for each 
test run, on a consistent moisture basis, in appropriate units of 
measure;
    11.4.3.9 Flags to indicate which test runs were used in the 
calculations;
    11.4.3.10 Arithmetic mean of the CEMS values, of the reference 
method values, and of their differences;
    11.4.3.11 Standard deviation, as specified in Equation 2-4 of 
Performance Specification 2 in appendix B to part 60 of this 
chapter;
    11.4.3.12 Confidence coefficient, as specified in Equation 2-5 
of Performance Specification 2 in appendix B to part 60 of this 
chapter; and

[[Page 9513]]

    11.4.3.13 Relative accuracy calculated using Equation 2-6 of 
Performance Specification 2 in appendix B to part 60 of this chapter 
or, if applicable, according to the alternative procedure for low 
emitters described in section 3.1.2.2 of this appendix. If 
applicable use a flag to indicate that the alternative RA 
specification for low emitters has been applied.
    11.4.4 Reporting Requirements for Diluent Gas, Flow Rate, and 
Moisture Monitoring Systems. For the certification, recertification, 
diagnostic, and QA tests of stack gas flow rate, moisture, and 
diluent gas monitoring systems that are certified and quality-
assured according to part 75 of this chapter, report the information 
in section 10.1.9.3 of this appendix.
    11.5 Quarterly Reports.
    11.5.1 Beginning with the report for the calendar quarter in 
which the initial compliance demonstration is completed or the 
calendar quarter containing the applicable date in Sec.  
63.10005(g), (h), or (j) (whichever is earlier), the owner or 
operator of any affected unit shall use the ECMPS Client Tool to 
submit electronic quarterly reports to the Administrator, in an XML 
format specified by the Administrator, for each affected unit (or 
group of units monitored at a common stack).
    11.5.2 The electronic reports must be submitted within 30 days 
following the end of each calendar quarter, except for units that 
have been placed in long-term cold storage.
    11.5.3 Each electronic quarterly report shall include the 
following information:
    11.5.3.1 The date of report generation;
    11.5.3.2 Facility identification information;
    11.5.3.3 The information in sections 10.1.2 through 10.1.7 of 
this appendix, as applicable to the type(s) of monitoring system(s) 
used to measure the pollutant concentrations and other necessary 
parameters.
    11.5.3.4 The results of all daily calibrations (including 
calibration transfer standard tests) of the HCl or HF monitor as 
described in section 10.1.8.1.1 of this appendix; and
    11.5.3.5 If applicable, the results of all daily flow monitor 
interference checks, in accordance with section 10.1.8.2 of this 
appendix.
    11.5.4 Compliance Certification. Based on reasonable inquiry of 
those persons with primary responsibility for ensuring that all HCl 
and/or HF emissions from the affected unit(s) have been correctly 
and fully monitored, the owner or operator shall submit a compliance 
certification in support of each electronic quarterly emissions 
monitoring report. The compliance certification shall include a 
statement by a responsible official with that official's name, 
title, and signature, certifying that, to the best of his or her 
knowledge, the report is true, accurate, and complete.

[FR Doc. 2012-806 Filed 2-15-12; 8:45 am]
BILLING CODE 6560-50-P`