[Federal Register Volume 76, Number 85 (Tuesday, May 3, 2011)]
[Proposed Rules]
[Pages 24976-25147]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2011-7237]



[[Page 24975]]

Vol. 76

Tuesday,

No. 85

May 3, 2011

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; Proposed Rule

  Federal Register / Vol. 76, No. 85 / Tuesday, May 3, 2011 / Proposed 
Rules  

[[Page 24976]]


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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Parts 60 and 63

[EPA-HQ-OAR-2009-0234; EPA-HQ-OAR-2011-0044, FRL-9286-1]
RIN 2060-AP52


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.

ACTION: Proposed rule.

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SUMMARY: The United States (U.S.) Environmental Protection Agency (EPA 
or Agency) is proposing national emission standards for hazardous air 
pollutants (NESHAP) from coal- and oil-fired electric utility steam 
generating units (EGUs) under Clean Air Act (CAA or the Act) section 
112(d) and proposing revised new source performance standards (NSPS) 
for fossil fuel-fired EGUs under CAA section 111(b). The proposed 
NESHAP would protect air quality and promote public health by reducing 
emissions of the hazardous air pollutants (HAP) listed in CAA section 
112(b). In addition, these proposed amendments to the NSPS are in 
response to a voluntary remand of a final rule. We also are proposing 
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.

DATES: Comments must be received on or before July 5, 2011. Under the 
Paperwork Reduction Act (PRA), comments on the information collection 
provisions are best assured of having full effect if the Office of 
Management and Budget (OMB) receives a copy of your comments on or 
before June 2, 2011.
    Public Hearing: EPA will hold three public hearings on this 
proposal. The dates, times, and locations of the public hearings will 
be announced separately. Oral testimony will be limited to 5 minutes 
per commenter. The EPA encourages commenters to provide written 
versions of their oral testimonies either electronically or in paper 
copy. Verbatim transcripts and written statements will be included in 
the rulemaking docket. If you would like to present oral testimony at 
one of the hearings, please notify Ms. Pamela Garrett, Sectors Policies 
and Programs Division (C504-03), U.S. EPA, Research Triangle Park, NC 
27711, telephone number (919) 541-7966; e-mail: [email protected]. 
Persons wishing to provide testimony should notify Ms. Garrett at least 
2 days in advance of each scheduled public hearing. For updates and 
additional information on the public hearings, please check EPA's Web 
site for this rulemaking, http://www.epa.gov/ttn/atw/utility/utilitypg.html. The public hearings will provide interested parties the 
opportunity to present data, views, or arguments concerning the 
proposed rule. EPA officials may ask clarifying questions during the 
oral presentations, but will not respond to the presentations or 
comments at that time. Written statements and supporting information 
submitted during the comment period will be considered with the same 
weight as any oral comments and supporting information presented at the 
public hearings.

ADDRESSES: Submit your comments, identified by Docket ID. No. EPA-HQ-
OAR-2011-0044 (NSPS action) or Docket ID No. EPA-HQ-OAR-2009-0234 
(NESHAP action), by one of the following methods:
     http://www.regulations.gov. Follow the instructions for 
submitting comments.
     http://www.epa.gov/oar/docket.html. Follow the 
instructions for submitting comments on the EPA Air and Radiation 
Docket Web site.
     E-mail: Comments may be sent by electronic mail (e-mail) 
to [email protected], Attention EPA-HQ-OAR-2011-0044 (NSPS action) 
or EPA-HQ-OAR-2009-0234 (NESHAP action).
     Fax: Fax your comments to: (202) 566-9744, Docket ID No. 
EPA-HQ-OAR-2011-0044 (NSPS action) or Docket ID No. EPA-HQ-OAR-2009-
0234 (NESHAP action).
     Mail: Send your comments on the NESHAP action to: EPA 
Docket Center (EPA/DC), Environmental Protection Agency, Mailcode: 
2822T, 1200 Pennsylvania Ave., NW., Washington, DC 20460, Docket ID No. 
EPA-HQ-OAR-2009-0234. Send your comments on the NSPS action to: EPA 
Docket Center (EPA/DC), Environmental Protection Agency, Mailcode: 
2822T, 1200 Pennsylvania Ave., NW., Washington, DC 20460, Docket ID. 
EPA-HQ-OAR-2011-0044. Please include a total of two copies. In 
addition, please mail a copy of your comments on the information 
collection provisions to the Office of Information and Regulatory 
Affairs, OMB, Attn: Desk Officer for EPA, 725 17th St., NW., 
Washington, DC 20503.
     Hand Delivery or Courier: Deliver your comments to: EPA 
Docket Center, EPA West, Room 3334, 1301 Constitution Ave., NW., 
Washington, DC 20460. Such deliveries are only accepted during the 
Docket's normal hours of operation (8:30 a.m. to 4:30 p.m., Monday 
through Friday, excluding legal holiday), and special arrangements 
should be made for deliveries of boxed information.
    Instructions: All submissions must include agency name and 
respective docket number or Regulatory Information Number (RIN) for 
this rulemaking. All comments will be posted without change and may be 
made available online at http://www.regulations.gov, including any 
personal information provided, unless the comment includes information 
claimed to be confidential business information (CBI) or other 
information whose disclosure is restricted by statute. Do not submit 
information that you consider to be CBI or otherwise protected through 
http://www.regulations.gov or e-mail. The http://www.regulations.gov 
Web site is an ``anonymous access'' system, which means EPA will not 
know your identity or contact information unless you provide it in the 
body of your comment. If you send an e-mail comment directly to EPA 
without going through http://www.regulations.gov, your e-mail address 
will be automatically captured and included as part of the comment that 
is placed in the public docket and made available on the Internet. If 
you submit an electronic comment, EPA recommends that you include your 
name and other contact information in the body of your comment and with 
any disk or CD-ROM you submit. If EPA cannot read your comment due to 
technical difficulties and cannot contact you for clarification, EPA 
may not be able to consider your comment. Electronic files should avoid 
the use of special characters, any form of encryption, and be free of 
any defects or viruses.
    Docket: All documents in the docket are listed in the http://www.regulations.gov index. Although listed in the index, some 
information is not publicly available (e.g., CBI or other information 
whose disclosure is restricted by statute). Certain other material, 
such as copyrighted material, will be publicly available only in hard 
copy form. Publicly available docket materials are available either 
electronically in http://www.regulations.gov or in hard copy at

[[Page 24977]]

the EPA Docket Center, Room 3334, 1301 Constitution Avenue, NW., 
Washington, DC. The Public Reading Room 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) 566-1742.

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; E-
mail 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; E-
mail address: [email protected].

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

I. General Information
    A. Executive Summary
    B. Does this action apply to me?
    C. What should I consider as I prepare my comments to EPA?
    D. Where can I get a copy of this document?
    E. When would a public hearing occur?
II. Background Information on the NESHAP
    A. Statutory Background
    B. Regulatory and Litigation Background
III. Appropriate and Necessary Finding
    A. Regulating EGUs Under CAA Section 112
    B. The December 2000 Appropriate and Necessary Finding Was 
Reasonable
    C. EPA Must Regulate EGUs Under Section 112 Because EGUs Were 
Properly Listed Under CAA Section 112(c)(1) and May Not Be Delisted 
Because They Do Not Meet the Delisting Criteria in CAA Section 
112(c)(9)
    D. New Analyses Confirm That It Remains Appropriate and 
Necessary To Regulate U.S. EGU HAP Under Section 112
IV. Summary of This Proposed NESHAP
    A. What source categories are affected by this proposed rule?
    B. What is the affected source?
    C. Does this proposed rule apply to me?
    D. Summary of Other Related D.C. Circuit Court Decisions
    E. EPA's Response to the Vacatur of the 2005 Action
    F. What is the relationship between this proposed rule and other 
combustion rules?
    G. What emission limitations and work practice standards must I 
meet?
    H. What are the startup, shutdown, and malfunction (SSM) 
requirements?
    I. What are the testing requirements?
    J. What are the continuous compliance requirements?
    K. What are the notification, recordkeeping, and reporting 
requirements?
    L. Submission of Emissions Test Results to EPA
    V. Rationale for This Proposed NESHAP
    A. How did EPA determine which subcategories and sources would 
be regulated under this proposed NESHAP?
    B. How did EPA select the format for this proposed rule?
    C. How did EPA determine the proposed emission limitations for 
existing EGUs?
    D. How did EPA determine the MACT floors for existing EGUs?
    E. How did EPA consider beyond-the-floor for existing EGUs?
    F. Should EPA consider different subcategories?
    G. How did EPA determine the proposed emission limitations for 
new EGUs?
    H. How did EPA determine the MACT floor for new EGUs?
    I. How did EPA consider beyond-the-floor for new EGUs?
    J. Consideration of Whether To Set Standards for HCl and Other 
Acid Gas HAP Under CAA Section 112(d)(4)
    K. How did we select the compliance requirements?
    L. What alternative compliance provisions are being proposed?
    M. How did EPA determine compliance times for this proposed 
rule?
    N. How did EPA determine the required records and reports for 
this proposed rule?
    O. How does this proposed rule affect permits?
    P. Alternative Standard for Consideration
VI. Background Information on the Proposed NSPS
    A. What is the statutory authority for this proposed NSPS?
    B. Summary of State of New York, et al., v. EPA Remand
    C. EPA's Response to the Remand
    D. EPA's Response to the Utility Air Regulatory Group's Petition 
for Reconsideration
VII. Summary of the Significant Proposed NSPS Amendments
    A. What are the proposed amended emissions standards for EGUs?
    B. Would owners/operators of any EGUs be exempt from the 
proposed amendments?
    C. What other significant amendments are being proposed?
VIII. Rationale for This Proposed NSPS
    A. How are periods of malfunction addressed?
    B. How did EPA determine the proposed emission limitations?
    C. Changes to the Affected Facility
    D. Additional Proposed Amendments
    E. Request for Comments on the Proposed NSPS Amendments
IX. Summary of Cost, Environmental, Energy, and Economic Impacts of 
This Proposed NSPS
X. Impacts of These Proposed Rules
    A. What are the air impacts?
    B. What are the energy impacts?
    C. What are the compliance costs?
    D. What are the economic impacts?
    E. What are the benefits of this proposed rule?
XI. Public Participation and Request for Comment
XII. 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

I. General Information

A. Executive Summary

    In December 2000, EPA appropriately concluded that it was 
appropriate and necessary to regulate hazardous air pollutants (HAP) 
from EGUs. Today, EPA confirms that finding and concludes that it 
remains appropriate and necessary to regulate these emissions from 
EGUs. Hazardous air pollutants from EGUs contribute to adverse health 
and environmental effects. EGUs are by far the largest U.S. 
anthropogenic sources of mercury (Hg) emissions into the air and emit a 
number of other HAP. Both the finding in 2000 and our conclusion that 
it remains appropriate and necessary to regulate HAP from EGUs are 
supported by the CAA and scientific and technical analyses.
    Mercury is a highly toxic pollutant that occurs naturally in the 
environment and is released into the atmosphere in significant 
quantities as the result of the burning of fossil fuels. Mercury in the 
environment is transformed into a more toxic form, methylmercury 
(MeHg), and because it is also a persistent pollutant, it accumulates 
in the food chain, especially the tissue of fish. When people consume 
these fish they consume MeHg, the consumption of which may cause 
neurotoxic effects. Children, and, in particular, developing

[[Page 24978]]

fetuses, are especially susceptible to MeHg effects because their 
developing bodies are more highly sensitive to its effects. In the 
December 2000 Finding, we estimated that about 7 percent of women of 
child-bearing age are exposed to MeHg at a level capable of causing 
adverse effects in the developing fetus, and that about 1 percent were 
exposed to 3 to 4 times that level. 65 FR 79827. Moreover, in the 1997 
Mercury Study Report to Congress (the ``Mercury Study''),\1\ we 
concluded that exposures among specific subpopulations including 
anglers, Asian-Americans, and members of some Native American Tribes 
may be more than two-times greater than those experienced by the 
average U.S. population (U.S. EPA 1997 Mercury Study Report to 
Congress, Volume IV, page 7-2).
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    \1\ U.S. EPA. 1997. Mercury Study Report to Congress. EPA-452/R-
97-003 December 1997.
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    In addition to Hg, EGUs are significant emitters of HAP metals such 
as arsenic (As), nickel (Ni), cadmium (Cd), and chromium (Cr), which 
can cause cancer; HAP metals with potentially serious noncancer health 
effect such as lead (Pb) and selenium (Se); and other toxic air 
pollutants such as the acid gases hydrogen chloride (HCl) and hydrogen 
fluoride (HF). Adverse noncancer health effects associated with non-Hg 
EGU HAP include chronic health disorders (e.g., irritation of the lung, 
skin, and mucus membranes, effects on the central nervous system, and 
damage to the kidneys), and acute health disorders (e.g., lung 
irritation and congestion, alimentary effects such as nausea and 
vomiting, and effects on the kidney and central nervous system). Three 
of the key metal HAP emitted by EGUs (As, Cr, and Ni) have been 
classified as human carcinogens, while another (Cd) is classified as a 
probable human carcinogen. Current national emissions inventories 
indicate that EGUs are responsible for 62 percent of the national total 
emissions of As, 22 percent of the national total emissions of Cr, and 
28 percent of the national total emissions of Ni to the atmosphere. 
Notably, EGUs are also responsible for 83 percent of the national total 
emissions of Se to the atmosphere.
    Congress recognized the threats posed by emissions of HAP and was 
dissatisfied with the pace of EPA's progress in reducing them prior to 
1990. As a result, it enacted significant changes to the CAA that 
required EPA to develop stringent standards for the control of these 
pollutants from both stationary and mobile sources. Congress included 
the requirements in the 1990 CAA amendments regarding acid rain that 
would reduce emissions of certain criteria pollutants from EGUs and 
result in the installation of controls that might achieve HAP emission 
reduction co-benefits. For that reason, it added the requirement for 
EPA to make a finding before it could regulate EGUs under section 112. 
Specifically, Congress required in the air toxics provisions that EPA 
conduct a study of the public health hazards anticipated to remain from 
EGU HAP emissions after imposition of these other provisions and 
regulate EGUs under section 112 if the Agency found, after considering 
the results of the study, that such regulation was appropriate and 
necessary. Congress also required EPA to conduct a study of Hg 
emissions from EGUs and other sources and consider the health and 
environmental effects of the emissions and the availability and cost of 
control technologies.
    Responding to Congress, EPA published the required studies 
detailing the hazards posed by emissions of Hg and the risks posed by 
emissions of Hg and other HAP from fossil fuel-fired EGUs. Following 
the publication of the studies and after collecting additional relevant 
data, EPA concluded in December 2000 that the threats to public health 
and the environment from emissions of Hg and other HAP from EGUs made 
it both appropriate and necessary to adopt regulations under section 
112 to reduce the emissions of Hg and other HAP from coal- and oil-
fired EGUs. As a result of its findings, EPA added these sources to the 
list of stationary sources subject to regulations governing the 
emissions of HAP. However, in a rulemaking effort completed in 2005, 
EPA reversed its findings and instead adopted regulations under other 
provisions of the CAA. The DC Circuit Court vacated the resulting 
regulations, noting that EPA had sidestepped important legal 
requirements in the CAA that govern the delisting of source categories. 
Those requirements provide that EPA can delist a source category only 
if it can demonstrate that no source within the listed category poses a 
lifetime cancer risk above one in one million to the individual most 
exposed and that emissions from no source in the category exceed the 
level that is adequate to protect public health with an ample margin of 
safety and that no adverse environmental effects will result from the 
emissions of any source. CAA 112(c)(9)(B). The DC Circuit Court's 
action restored EPA's December 2000 determination that it was 
appropriate and necessary to regulate coal- and oil-fired EGUs under 
section 112, and EGUs remain a listed source category.
    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 EGUs under section 112. Now, more than 10 years 
have passed since EPA's determination that toxic emissions from coal- 
and oil-fired EGUs pose a threat to public health and the environment. 
Although not required, EPA conducted additional, extensive technical 
analyses based on more recent data, and those analyses confirm that it 
remains appropriate and necessary to regulate HAPs from coal- and oil-
fired EGUs. Accordingly and without further delay, we are proposing a 
set of HAP emission standards for coal- and oil-fired EGUs that can be 
met with existing technology that has been available for a significant 
time.
    EPA acknowledges that although EGUs contribute significantly to the 
total amount of U.S. anthropogenic Hg emissions, other sources both 
here and abroad also contribute significantly to the global atmospheric 
burden and U.S. deposition of Hg. It is estimated that the U.S. 
contributes 5 percent to global anthropogenic Hg and 2 percent the 
total global Hg pool.\2\ However, as the U.S. Supreme Court has noted 
in decisions as recently as Massachusetts v. EPA, regarding the problem 
of climate change, it is not necessary to show that a problem will be 
entirely solved by the action being taken, nor that it is necessary to 
cure all ills before addressing those judged to be significant. 549 
U.S. 497, 525 (2007).
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    \2\ Based on 2005 U.S. emissions of 105 tons, and global 
emissions of 2,100 tons from UNEP. Mercury emissions are discussed 
more fully in Section III.D.1 of this preamble.
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    At the time it published the December 2000 Finding, EPA identified 
certain technologies capable of significantly reducing Hg and other HAP 
emissions. Since then, additional technologies and improvements to 
those previously identified have become available. These technologies 
are also often effective at reducing significantly the emissions of 
other conventional pollutants such as SO2 and PM, thereby 
conferring even greater health co-benefits. As today's notice discusses 
further, the reductions expected from the adopted final rule will 
produce substantially greater co-benefits to health and the environment 
than they will cost to affected companies. We further believe that 
these reductions can be achieved without significantly affecting the 
availability and cost of electricity to

[[Page 24979]]

consumers. In those instances in which such concerns do arise, the 
Federal government will work with companies to ensure a reliable and 
reasonably-priced supply of electricity. Moreover, in its assessment of 
the impacts of today's proposed rule on jobs and the economy, EPA finds 
that more jobs will be created in the air pollution control technology 
production field than may be lost as the result of compliance with 
these proposed rules.
    A number of EGUs operating today were built in the 1950s and 1960s, 
using now-obsolete and inefficient technologies. Today, new units are 
far more efficient in their production of electricity, their use of 
fuel, and the relative quantities of pollution emitted. To the extent 
that some of the oldest, least efficient, least controlled units are 
retired by companies who elect not to invest in controlling them, 
assessments included in the docket to today's notice of proposed 
rulemaking indicate that there will be a sufficient supply of 
electricity from newer units. In fact, one consequence of today's 
proposed rule, if adopted as a final rule, will 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. Thus, this proposed rule will require companies to make a 
decision--control HAP emissions from virtually uncontrolled sources or 
retire these sometimes 60 year old units and shift their emphasis to 
more efficient, cleaner modern methods of generation, including modern 
coal-fired generation.
    For the reasons summarized above and discussed in detail in this 
document, the standards being proposed today will be effective at 
significantly reducing emissions of Hg and an array of other toxic 
pollutants from coal- and oil-fired EGUs. In addition, as a result of 
the HAP reductions and co-benefits of these rules, many premature 
deaths from exposure to air pollution will be avoided by the 
application of controls that are well-known, broadly applied, and 
available. To the extent that isolated issues remain concerning the 
availability of electricity in some more remote parts of the country, 
we believe that EPA has the ability to work with companies making good 
faith efforts to comply with the standards so that consumers in those 
areas are not adversely affected.
    Consistent with the recently issued Executive Order (EO) 13563, 
``Improving Regulation and Regulatory Review,'' we have estimated the 
cost and benefits of the proposed rule. The estimated net benefits of 
our proposed rule at a 3 percent discount rate are $48 to 130 billion 
or $42 to $120 billion at a 7 percent discount rate.

         Summary of the Monetized Benefits, Social Costs, and Net Benefits for the Proposed Rule in 2016
                                              [Millions of 2007$] a
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                                                  3% Discount rate                     7% Discount rate
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Total Monetized Benefits b............  $59,000 to $140,000................  $53,000 to $130,000.
Hg-related Benefits c.................  $4.1 to $5.9.......................  $0.45 to $0.89.
CO2-related Benefits..................  $570...............................  $570.
PM2.5-related Co-benefits d...........  $58,000 to $140,000................  $53,000 to $120,000.
Total Social Costs e..................  $10,900............................  $10,900.
Net Benefits..........................  $48,000 to $130,000................  $42,000 to $130,000.
                                       -------------------------------------------------------------------------
Non-monetized Benefits................  Visibility in Class I areas.
                                        Cardiovascular effects of Hg exposure.
                                        Other health effects of Hg exposure.
                                        Ecosystem effects.
                                        Commercial and non-freshwater fish consumption.
----------------------------------------------------------------------------------------------------------------
a All estimates are for 2016, and are rounded to two significant figures. The net present value of reduced CO2
  emissions are calculated differently than other benefits. The same discount rate used to discount the value of
  damages from future emissions (SCC at 5, 3, 2.5 percent) is used to calculate net present value of SCC for
  internal consistency. This table shows monetized CO2 co-benefits at discount rates at 3 and 7 percent that
  were calculated using the global average SCC estimate at a 3 percent discount rate because the interagency
  workgroup on this topic deemed this marginal value to be the central value. In section 6.6 of the RIA we also
  report the monetized CO2 co-benefits using discount rates of 5 percent (average), 2.5 percent (average), and 3
  percent (95th percentile).
b The total monetized benefits reflect the human health benefits associated with reducing exposure to MeHg,
  PM2.5, and ozone.
c Based on an analysis of health effects due to recreational freshwater fish consumption.
d The reduction in premature mortalities from account for over 90 percent of total monetized PM2.5 benefits.
e Social costs are estimated using the MultiMarket model, in order to estimate economic impacts of the proposal
  to industries outside the electric power sector. Details on the social cost estimates can be found in Chapter
  9 and Appendix E of the RIA.

    For more information on how EPA is addressing EO 13563, see the 
executive order discussion, later in the preamble.

B. Does this action apply to me?

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

     Table 1--Potentially Affected Regulated Categories and Entities
------------------------------------------------------------------------
                                                        Examples of
           Category              NAICS code \1\    potentially regulated
                                                         entities
------------------------------------------------------------------------
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
                                                   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.


[[Page 24980]]

    This table is not intended to be exhaustive, but rather provides a 
guide for readers regarding entities likely to be affected by this 
action. To determine whether your facility, company, business, 
organization, etc., would 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 63.9982. 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).

C. What should I consider as I prepare my comments to EPA?

    Do not submit information containing CBI to EPA through http://www.regulations.gov or e-mail. Send or deliver information identified 
as CBI only to the following address: Roberto Morales, OAQPS Document 
Control Officer (C404-02), Office of Air Quality Planning and 
Standards, U.S. Environmental Protection Agency, Research Triangle 
Park, North Carolina 27711, Attention: Docket ID EPA-HQ-OAR-2011-0044 
(NSPS action) or Docket ID EPA-HQ-OAR-2009-0234 (NESHAP action). 
Clearly mark the part or all of the information that you claim to be 
CBI. For CBI information in a disk or CD-ROM that you mail to EPA, mark 
the outside of the disk or CD-ROM as CBI and then identify 
electronically within the disk or CD-ROM the specific information that 
is claimed as CBI. In addition to one complete version of the comment 
that includes information claimed as CBI, a copy of the comment that 
does not contain the information claimed as CBI must be submitted for 
inclusion in the public docket. Information so marked will not be 
disclosed except in accordance with procedures set forth in 40 CFR part 
2.

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

    In addition to being available in the docket, an electronic copy of 
this proposed rule will also be available on the Worldwide Web (WWW) 
through the Technology Transfer Network (TTN). Following signature, a 
copy of the proposed rule 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.

E. When would a public hearing occur?

    EPA will hold three public hearings on this proposal. The dates, 
times, and locations of the public hearings will be announced 
separately. If you would like to present oral testimony at one of the 
hearings, please notify Ms. Pamela Garrett, Sectors Policies and 
Programs Division (C504-03), U.S. EPA, Research Triangle Park, NC 
27711, telephone number (919) 541-7966; e-mail: [email protected]. 
Persons wishing to provide testimony should notify Ms. Garrett at least 
2 days in advance of the public hearings. For updates and additional 
information on the public hearings, please check EPA's Web site for 
this rulemaking, http://www.epa.gov/ttn/atw/utility/utilitypg.html.

II. Background Information on the NESHAP

    In 1990, Congress substantially rewrote provisions of the CAA 
addressing emissions of HAP from large and small stationary sources in 
the U.S. Collectively, these sources emit into the air millions of 
pounds of HAP each year, chemicals that are known to cause or are 
suspected of causing cancer, birth defects, reproduction problems, and 
other serious health effects. Many of the sources that emit air toxics 
are located in urban areas, which generally include predominantly low 
income, minority or otherwise vulnerable communities, where dense 
populations mean that large numbers of people may be exposed.
    Since 1990, EPA has promulgated regulations covering over 50 
industrial sectors, requiring the use of available control technology 
and other practices to reduce emissions. These standards have reduced 
emissions of HAP from American industry by more than 60 percent. HAP 
emissions from smaller sources such as dry cleaners and auto body shops 
have declined by 30 percent, also due to CAA standards. Greater 
reductions are expected as greater numbers of smaller sources adopt 
pollution prevention, efficiency, or install control technologies to 
comply with EPA emission standards. Emissions from the mobile source 
sector have also been addressed. Controls for fuels and vehicles are 
expected to reduce selected HAP from vehicles by more than 75 percent 
by 2020.
    EGUs are the most significant source of HAP in the country that 
remains unaddressed by Congress's air toxics program. EGUs emit 
multiple HAP of concern and are by far the largest remaining source of 
Hg, which is one of the more highly toxic chemicals on Congress's list 
of HAP and which, once released, stays in the environment permanently. 
Coal- and oil-fired EGUs also emit HAP such as As, other metals and 
acid gases in amounts significantly higher than almost any other 
industrial sector. They are located in nearly every state, and 
emissions from their stacks affect people nearby as well as hundreds of 
miles away.
    Congress provided a specific path for EPA to regulate HAP emissions 
from EGUs. It gave explicit instructions about scientific studies EPA 
needed to develop and then consider in determining whether it was 
``appropriate and necessary'' to regulate HAP emissions from EGUs. 
Congress anticipated that EPA would complete the studies by 1994. In 
2000, EPA found that it was indeed ``appropriate and necessary'' to 
regulate HAP emissions from EGUs under section 112. In the decade that 
has passed since EPA made that finding, EGUs have continued to emit Hg 
and other HAP, and there are still no national limits on the amount of 
Hg and other HAP that EGUs can release into the air. And, although some 
plants have installed available and effective control technologies that 
reduce these emissions, there is no requirement for EGUs to control for 
Hg and other HAP.
    As our new analyses demonstrate, it remains both appropriate and 
necessary to set standards for coal- and oil-fired EGUs to protect 
public health and the environment from the adverse effects of HAP 
emissions from EGUs. The Agency's appropriate and necessary finding was 
correct in 2000, and it remains correct today. EPA proposes to set 
standards for coal- and oil-fired EGUs that will reduce emissions of 
Hg, Ni and other metal HAP, acid gas HAP, and other harmful HAP. These 
standards are based on available control technologies and other 
practices already used by the better-controlled and lower-emitting 
EGUs. They are achievable, we believe they can be implemented without 
disruption to the reliable provision of electricity, and will deliver 
health protection across the U.S.
    In this section, we provide an overview of the relevant statutory, 
regulatory, and litigation background.

A. Statutory Background

    Congress enacted section 112 to address HAP emissions from 
stationary sources. Section 112 contains provisions specific to EGUs, 
which we will address in this preamble, but we begin with a summary of 
the overall structure and purpose of the section 112 program.
    Prior to the 1990 Amendments, the CAA required EPA to regulate HAP 
solely on the basis of risk to human

[[Page 24981]]

health. Legislative History of the CAA Amendments of 1990 
(``Legislative History''), at 3174-75, 3346 (Comm. Print 1993). 
Congress was dissatisfied with the slow pace of exclusively risk-based 
regulation of HAP prior to 1990, however, and, as a result, 
substantially amended the CAA in 1990, setting forth a two-stage 
approach for regulating HAP emissions. Under the first stage, Congress 
directed EPA to issue technology-based emission standards for listed 
source categories. CAA sections 112 (c)-(d). In the second stage, which 
occurs ``within eight years'' of the imposition of the technology-based 
standards, EPA must consider whether residual risks remain after 
imposition of the MACT standards that warrant more stringent standards 
to protect human health or to prevent an adverse environmental effect. 
CAA section 112(f)(2)(A).
    In addition to adopting this two-phased approach to standard-
setting, Congress included a series of rigorous deadlines for EPA, 
including deadlines for listing categories and issuing emission 
standards for such categories. See, e.g., CAA section 112(e)(1). Thus, 
in substantially amending CAA section 112 in 1990, Congress sought 
prompt and permanent reductions of HAP emissions from stationary 
sources--first through technology-based standards, and then further, as 
necessary, through risk-based standards designed to protect human 
health and the environment.
    The criteria for regulation differ in section 112 depending on 
whether the source is a major source or an area source. A ``major 
source'' is any stationary source \3\ or group of stationary sources at 
a single location and under common control that emits or has the 
potential to emit 10 tons or more per year of any HAP or 25 tons or 
more per year of any combination of HAP. See CAA 112(a)(1). An ``area 
source'' is any stationary source of HAP that is not a ``major 
source.'' See CAA 112(a)(2). For major sources, EPA must list a 
category under section 112(c)(1) if at least one stationary source in 
the category meets the definition of a major source.\4\ For area 
sources, EPA must list if: (1) EPA determines that the category of area 
sources presents a threat of adverse effects to human health or the 
environment that warrants regulation under CAA section 112; or (2) the 
category of area sources falls within the purview of CAA section 
112(k)(3)(B) (the Urban Area Source Strategy). See CAA section 
112(c)(3).
---------------------------------------------------------------------------

    \3\ A ``stationary source'' of HAP is any building, structure, 
facility or installation that emits or may emit any air pollutant. 
See CAA Section 112(a)(3).
    \4\ Congress required EPA to publish a list of categories and 
subcategories of major sources and area sources by November 15, 
1991. See CAA 112(c)(1) & (c)(3). EPA published the initial list on 
July 16, 1992. See 57 FR 31576, July 16, 1992. EPA did not include 
EGUs on the initial section 112(c) list because Congress required 
EPA to conduct and consider the results of the study required by 
section 112(n)(1)(A) before regulating these units. At the time of 
the initial listing, EPA had not completed the study required by 
section 112(n)(1)(A).
---------------------------------------------------------------------------

    Congress established a specific structure for determining whether 
to regulate EGUs under section 112.\5\ Specifically, Congress enacted 
CAA section 112(n)(1).
---------------------------------------------------------------------------

    \5\ ``Electric utility steam generating unit'' is defined as any 
``fossil fuel fired combustion unit of more than 25 megawatts that 
serves a generator that produces electricity for sale.'' See CAA 
112(a)(8).
---------------------------------------------------------------------------

    In section 112(n)(1)(A), EPA is directed to conduct a study 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, and to report the results of such study to 
Congress by November 15, 1993 (Utility Study Report to Congress; \6\ 
the ``Utility Study''). We discuss this study further below in 
conjunction with the other studies Congress required be conducted with 
respect to EGUs under section 112(n)(1). The last sentence of section 
112(n)(1)(A) provides that EPA shall regulate EGUs under CAA section 
112 ``if the Administrator finds such regulation is appropriate and 
necessary, after considering the results of the [Utility Study] * * *'' 
Thus, section 112(n)(1)(A) governs how the Administrator decides 
whether to list EGUs for regulation under section 112. See New Jersey, 
517 F.3d at 582 (``Section 112(n)(1) governs how the Administrator 
decides whether to list EGUs; it says nothing about delisting EGUs.'').
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    \6\ US EPA. Study of Hazardous Air Pollutant Emissions from 
Electric Utility Steam Generating Units --Final Report to Congress. 
EPA-453/R-98-004a. February 1998.
---------------------------------------------------------------------------

    Once a source category is listed pursuant to section 112(c), the 
next step is for EPA to establish technology-based emission standards 
under section 112(d). Under section 112(d), EPA must establish emission 
standards for major sources that ``require the maximum degree of 
reduction in emissions of the HAP subject to this section'' that EPA 
determines is achievable taking into account certain statutory factors. 
These 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 emissions 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). This level of minimum stringency 
is referred to as the MACT floor, and 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). EPA also must 
consider more stringent ``beyond-the-floor'' control options. When 
considering beyond-the-floor options, EPA must consider not only the 
maximum degree of reduction in emissions of HAP, but must take into 
account costs, energy, and nonair 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).
    CAA section 112(d)(4) authorizes EPA to set a health-based standard 
for a limited set of HAP for which a health threshold has been 
established, and that standard must provide for ``an ample margin for 
safety.'' 42 U.S.C. 7412(d)(4). As these standards are potentially 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, section 112(d)(5) authorizes EPA to issues 
standards or requirements that provide for the use of generally 
available control technologies (GACT) or management practices in lieu 
of promulgating standards pursuant to sections 112(d)(2) and (3).
    As noted above, Congress required that various reports concerning 
EGUs be completed. The first report, the Utility Study, required 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. This report was required by November 15, 1993. 
The second report, due on November 15, 1994, directed EPA to ``conduct 
a study of mercury emissions from [EGUs], municipal waste combustion 
units, and other sources, including area sources.'' See CAA section 
112(n)(1)(B). In conducting the Mercury study Congress directed EPA to 
``consider the rate and mass of emissions, the health and environmental 
effects of such emissions, technologies which are available to control 
such emissions, and the costs of such technologies.'' Id. EPA completed 
both of these reports by 1998.

[[Page 24982]]

    The last required report was to be completed by the National 
Institute of Environmental Health Sciences (NIEHS) and submitted to 
Congress by November 15, 1993. CAA section 112(n)(1)(C) directed NIEHS 
to conduct ``a study to determine the threshold level of Hg exposure 
below which adverse human health effects are not expected to occur.'' 
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. NIEHS submitted this Report to Congress 
in August, 1995.
    In addition, Congress, in conference report language associated 
with EPA's fiscal year 1999 appropriations, directed EPA to fund the 
National Academy of Sciences (NAS) to perform an independent evaluation 
of the available data related to the health impacts of MeHg 
(``Toxicological Effects of Methylmercury,'' hereinafter, NAS Study or 
MeHg Study).\7\ H.R. Conf. Rep. No. 105-769, at 281-282 (1998). 
Specifically, NAS was tasked with advising EPA as to the appropriate 
reference dose (RfD) for MeHg, which 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. 
65 FR 79826. In that same conference report, Congress indicated that 
EPA should not make the appropriate and necessary regulatory 
determination for Hg emissions until EPA had reviewed the results of 
the NAS Study. See H.R. Conf. Rep. No. 105-769, at 281-282 (1998).
---------------------------------------------------------------------------

    \7\ 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. Many of the peer-reviewed articles cited 
in this section are publications originally cited in the NAS report.
---------------------------------------------------------------------------

    The NAS Study evaluated the same issues as those required to be 
considered under section 112(n)(1)(C). The NAS Study was completed 5 
years after the NIEHS Study, and, thus, considered additional 
information not available to NIEHS. Because Congress required that the 
same issues be addressed in both the NAS and NIEHS Studies and the NAS 
Study was issued after the NIEHS study, we discuss, for purposes of 
this document, the content of the NAS Study, as opposed to the NIEHS 
Study.

B. Regulatory and Litigation Background

    EPA conducted the studies required by section 112(n)(1) concerning 
utility HAP emissions. Prior to issuance of the Mercury Study, EPA 
engaged in two extensive external peer reviews of the document. 
Although EPA missed the statutory deadline for completing the studies, 
the Mercury Study and the Utility Study were complete by 1998. The 
NIEHS study was completed in 1995, and the NAS Study was completed in 
2000.
    In December 2000, after considering public input, the studies 
required by section 112(n)(1) and other relevant information, including 
Hg emissions data from EGUs, EPA determined that it was appropriate and 
necessary to regulate EGUs under CAA section 112. Based on that 
determination, the Agency listed such units for regulation under 
section 112(c).
    Pursuant to a settlement agreement, the deadline for issuing 
emission standards was March 15, 2005. However, instead of issuing 
emission standards pursuant to section 112(d), on March 15, 2005, EPA 
delisted EGUs, finding that it was neither appropriate nor necessary to 
regulate such units under section 112. That attempt to delist was 
subsequently invalidated by the DC Circuit Court.
1. Studies Related to HAP Emissions From EGUs
a. The Utility Study
    EPA issued the Utility Study in February 1998, over 4 years after 
the statutory deadline. The Utility Study included numerous analyses. 
EPA first collected HAP emissions test data from 52 EGUs, including a 
range of coal-, oil-, and natural gas-fired units, and the test data 
along with facility specific information were used to estimate HAP 
emissions from all 684 utility facilities. EPA determined that 67 HAP 
were emitted from EGUs. In addition, the study evaluated HAP emissions 
based on two scenarios: (1) 1990 base year; and (2) 2010 projected 
emissions. The 2010 scenario was selected to meet the section 
112(n)(1)(A) mandate to evaluate hazards ``after imposition of the 
requirements of the Act.'' EPA also considered potential control 
strategies for the identified HAP consistent with section 112(n)(1)(A).
    EPA evaluated exposures, hazards, and risks due to HAP emissions 
from coal-, oil-, and natural gas-fired EGUs. EPA conducted a screening 
level assessment of all 67 HAP to prioritize the HAP for further 
analysis. A total of 14 HAP were identified as priority HAP that would 
be further assessed. Twelve HAP (As, beryllium (Be), Cd, Cr, manganese 
(Mn), Ni, HCl, HF, acrolein, dioxins, formaldehyde, and radionuclides) 
were identified as a priority for further assessment based on 
inhalation exposure and risk. Six HAP (Hg, radionuclides, As, Cd, Pb, 
and dioxins) were considered a priority for multipathway assessment of 
exposure and risk.
    Based on the inhalation estimates for the priority HAP, EPA 
determined that As and Cr emissions from coal-fired EGUs and Ni 
emissions from oil-fired EGUs contributed most to the potential cancer 
related inhalation risks, but those risks were not high. The non-cancer 
risk assessment due to inhalation exposure indicated exposures were 
well below the reference levels.
    The Agency also conducted multipathway assessments for the six HAP 
identified above. Based on these analyses, EPA determined that Hg from 
coal-fired EGUs was the HAP of greatest potential concern. In addition, 
the screening multipathway assessments for dioxins and As suggested 
that these two HAP were of potential for multipathway risk.
    In addition to the 1990 analysis, EPA also estimated emissions and 
inhalation risks for the year 2010. HAP emissions from coal-fired 
utilities were predicted to increase by 10 to 30 percent by the year 
2010. Predicted changes included the installation of scrubbers for a 
small number of facilities, the closing of a few facilities, and an 
increase in fuel consumption of other facilities. For oil-fired plants, 
emissions and inhalation risks were estimated to decrease by 30 to 50 
percent by the year 2010, primarily due to projected reductions in use 
of oil for electricity generation. Multipathway risks for 2010 were not 
assessed.
    In estimating future emissions from EGUs, EPA primarily evaluated 
the effect of implementation of the Acid Rain Program (ARP) on HAP 
emissions from EGUs. The 2010 scenario also included estimated changes 
in emissions resulting from projected trends in fuel choices and power 
demands.
    Table 2 of this preamble presents estimated emissions for a subset 
of priority HAP for 1990 and 2010.

[[Page 24983]]



                                                 Table 2--Nationwide Emissions for Six Priority HAP, tpy
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                       Coal                             Oil                         Natural gas
                           HAP                           -----------------------------------------------------------------------------------------------
                                                               1990            2010            1990            2010            1990            2010
--------------------------------------------------------------------------------------------------------------------------------------------------------
Arsenic.................................................              61              71            5               3             0.15             0.25
Chromium................................................              73              87            4.7             2.4   ..............  ..............
Mercury.................................................              46              60            0.25            0.13          0.0015           0.024
Nickel..................................................              58              69          390             200             2.2              3.5
Hydrogen chloride.......................................         143,000         155,000        2,900           1,500            NM               NM
Hydrogen fluoride.......................................          20,000          26,000          140              73            NM               NM
--------------------------------------------------------------------------------------------------------------------------------------------------------

    Numerous potential alternative control strategies for reducing HAP 
emissions from EGUs were identified. These included pre-combustion 
controls (e.g., fuel switching, coal cleaning), post combustion 
controls (e.g., PM controls, SO2 controls), and improving 
efficiency in supply or demand. For example, coal cleaning tends to 
remove at least some of all the trace metals. EPA also concluded that 
PM controls tend to effectively remove the trace metals (excluding Hg). 
The Utility Study also found that flue gas desulfurization (FGD) units 
were less effective at removing trace metals and exhibited more 
variability in removal of those metals than PM control, but FGD were 
more effective at reducing acid gas HAP.
b. The Mercury Study
    EPA issued the Mercury Study in December 1997, 3 years after the 
statutory deadline. The Mercury Study assessed the magnitude of U.S. Hg 
emissions by source, the health and environmental implications of those 
emissions, and the availability and cost of control technologies.
    According to the Mercury Study, Hg cycles in the environment as a 
result of natural and human (anthropogenic) activities. Most of the Hg 
in the atmosphere is elemental Hg vapor, which circulates in the 
atmosphere for up to a year, and, hence, can be widely dispersed and 
transported thousands of miles from likely sources of emission. The 
Mercury Study also found that most of the Hg in water, soil, sediments, 
or plants and animals is in the form of inorganic Hg salts and organic 
forms of Hg (e.g., MeHg). The inorganic form of Hg, when either bound 
to airborne particles or in a gaseous form, is readily removed from the 
atmosphere by precipitation and is also dry deposited. Wet deposition 
is the primary mechanism for transporting Hg from the atmosphere to 
surface waters and land. Even after it deposits, Hg commonly is emitted 
back to the atmosphere either as a gas or associated with particles, to 
be re-deposited elsewhere.
    The Mercury Study estimated that in 1994-1995, anthropogenic U.S. 
Hg emissions were about 158 tons annually. Roughly 87 percent of those 
emissions were from combustion sources, including waste and fossil fuel 
combustion. According to the Mercury Study, current anthropogenic 
emissions were only one part of the Hg cycle. The Mercury Study noted 
that current releases from human activities were adding to the Hg 
reservoirs that already exist in land, water, and air, both naturally 
and as a result of prior human activities. The Mercury Study concluded 
that the flux of Hg from the atmosphere to land or water at any one 
location is comprised of contributions from the natural global cycle, 
including re-emissions from the oceans, international sources, regional 
sources, and local sources.
    The Mercury Study further described a computer simulation of long-
range transport of Hg, which suggested that about one-third 
(approximately 52 tons) of U.S. anthropogenic emissions are deposited, 
through wet and dry deposition, within the lower 48 states. The 
remaining two-thirds (approximately 107 tons) was estimated to be 
transported outside of U.S. borders where it would diffuse into the 
global reservoir. The computer simulation further suggested that 
another 35 tons of Hg from the global reservoir outside the U.S. was 
deposited annually in the U.S. for a total deposition in the U.S. of 
roughly 87 tons per year (tpy).
    The Mercury Study also found that fish consumption dominates the 
pathway for human and wildlife exposure to MeHg and that there was a 
plausible link between anthropogenic releases of Hg from industrial and 
combustion sources in the U.S. and MeHg in fish. In the Mercury Study, 
EPA explained that, given the current scientific understanding of the 
environmental fate and transport of this element, it was not possible 
to quantify how much of the MeHg in fish consumed by the U.S. 
population results from U.S. anthropogenic emissions, as compared to 
other sources of Hg (such as natural sources and re-emissions from the 
global pool).
    The Mercury Study noted that those who regularly and frequently 
consume large amounts of fish--either marine species that typically 
have much higher levels of MeHg than other species, or freshwater fish 
that have been affected by Hg pollution--are more highly exposed. 
Because the developing fetus may be the most sensitive to the effects 
from MeHg, women of child-bearing age were the population of greatest 
interest. EPA concluded in the Mercury Study that approximately 7 
percent of women of child-bearing age (i.e., between the ages of 15 and 
44) were exposed to MeHg at levels exceeding the RfD.
    Finally, the Mercury Study concluded that piscivorous (fish-eating) 
birds and mammals were more highly exposed to Hg than any other known 
component of aquatic ecosystems, and that adverse effects of Hg on 
fish, birds and mammals include death, reduced reproductive success, 
impaired growth and development, and behavioral abnormalities. The 
Mercury Study also evaluated Hg emissions control technologies and the 
costs of such technologies.
c. The NAS Methylmercury Study
    In the appropriations report for EPA's fiscal 1999 funding, 
Congress directed EPA to fund the NAS to perform an independent study 
on the toxicological effects of MeHg and to prepare recommendations on 
the establishment of a scientifically appropriate MeHg exposure RfD. In 
response, EPA contracted with NAS, which conducted an 18-month study of 
the available data on the health effects of MeHg and reported its 
findings to EPA in July 2000.
    The EPA included four charges to NAS: (1) Evaluate the body of 
evidence that led to EPA's current RfD for MeHg, and on the basis of 
available human epidemiological and animal toxicity data, determine 
whether the critical study, end point of toxicity, and uncertainty 
factors used by EPA in the derivation of the RfD for MeHg are 
scientifically appropriate, including

[[Page 24984]]

consideration of sensitive populations; (2) evaluate any new data not 
considered in the Mercury Study that could affect the adequacy of EPA's 
MeHg RfD for protecting human health; (3) consider exposures in the 
environment relevant to evaluation of likely human exposures 
(especially to sensitive subpopulations and especially from consumption 
of fish that contain MeHg), and include in the evaluation a focus on 
those elements of exposure relevant to the establishment of an 
appropriate RfD; and (4) identify data gaps and make recommendations 
for future research.
    The NAS held both public and closed sessions wherein they evaluated 
data and presentations from government agencies, trade organizations, 
public interest groups, and concerned citizens. The NAS also evaluated 
new findings that had emerged since the development of EPA's 1995 RfD 
and met with the investigators of major ongoing epidemiological 
studies.
    The NAS Study concluded that the value of EPA's 1995 RfD for MeHg, 
0.1 micrograms per kilogram ([micro]g/kg) per day, was a scientifically 
appropriate level for the protection of public health. The NAS Study 
further concluded that data from both human and animal studies 
indicated that the developing nervous system was a sensitive target 
organ for low-dose MeHg exposure. The NAS Study indicated that there 
was evidence that exposure to MeHg in humans and animals can have 
adverse effects on both the developing and adult cardiovascular system. 
Some of the studies observed adverse cardiovascular effects at or below 
MeHg exposure levels associated with neurodevelopmental effects. The 
weight of evidence for carcinogenicity of MeHg was inconclusive. There 
was also evidence from animal studies that the immune and reproductive 
systems are sensitive targets for MeHg toxicity.
    According to the NAS Study, the estimates of MeHg exposures in the 
U.S. population indicated that the risk of adverse effects from then-
current MeHg exposures in the majority of the population was low. 
However, the NAS Study concluded that individuals with high MeHg 
exposures from frequent fish consumption might have little or no margin 
of safety (i.e., exposures of high-end consumers are close to those 
with observable adverse effects). The NAS Study also noted that the 
population at highest risk was the children of women who consumed large 
amounts of fish and seafood during pregnancy. The NAS Study further 
concluded that the impact on that population was likely to be 
sufficient to result in an increase in the number of children who 
struggle to keep up in school and might require remedial classes or 
special education.
2. EPA's December 2000 Appropriate and Necessary Finding
    On December 20, 2000, 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 section 112 and added such units to the list 
of source categories subject to regulation under section 112(d). In 
making that finding, 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 EPA obtained 
pursuant to an information collection request (ICR) under the authority 
of section 114 of the CAA. 65 FR 79826-27. EPA collected data on the Hg 
content of coal from all coal-fired EGUs for the calendar year 1999 and 
Hg emissions stack test data for certain coal-fired EGUs. 65 FR 79826. 
EPA also solicited data from the public through a February 29, 2000, 
notice (65 FR 10783). The public had an opportunity to provide their 
views on what the section 112(n)(1)(A) appropriate and necessary 
regulatory finding should be at a public meeting in Chicago, Illinois, 
on June 13, 2000 (65 FR 18,992). 65 FR 79826.
    In the December 2000 notice, EPA explained that it evaluated EGUs 
based on the type of fossil fuel combusted (i.e., coal, oil, and 
natural gas). The December 2000 Finding focused primarily on Hg 
emissions from coal-fired EGUs. Mercury was determined to be the HAP of 
greatest concern in the Utility Study. In evaluating Hg emissions from 
coal-fired EGUs, EPA stated that the quality of the Hg data available 
in 2000 was considerably better than the data available for the Utility 
Study because of the results of the 1999 ICR. The new data also 
corroborated the Hg emissions estimates in the study. 65 FR 79828. In 
the finding, EPA explained that Hg is highly toxic and persistent and 
that it bioaccumulates in the food chain; that Hg air emissions from 
all sources, including EGUs, deposit on the land where the Hg may 
transform into MeHg, which is the primary type of Hg that accumulates 
in fish tissue; and that eating Hg contaminated fish was the primary 
route of exposure for humans. 65 FR 79827. The potential hazard of most 
concern was determined to be consumption by subsistence fish-eating 
populations and women of childbearing age because of the adverse 
effects that Hg poses to the developing fetus. 65 FR 79827. Finally, 
EPA noted that approximately 7 percent of women of child bearing age 
were exposed to levels of MeHg that exceeded the RfD. 65 FR 79827.
    EPA further estimated that about 60 percent of the total Hg 
deposited in the U.S. came from anthropogenic air emissions originating 
in the U.S. and that EGUs contributed approximately 30 percent of those 
anthropogenic air emissions. 65 FR 79827. Based on the record before 
the Agency at the time, EPA determined that there was a plausible link 
between Hg emissions from EGUs and MeHg in fish and that Hg emissions 
from EGUs were a threat to public health and the environment. 65 FR 
79827.
    In discussing the non-Hg HAP from coal- and oil-fired EGUs, EPA 
stated that HAP metals such as As, Cr, Ni, and Cd are of potential 
concern for carcinogenic effects. 65 FR 79827. EPA acknowledged that 
the risk assessments conducted for these HAP indicated that cancer 
risks were not high, but the Agency could not conclude the potential 
concern for public health was eliminated for those metals. 65 FR 79827. 
EPA further stated that dioxins, HCl, and HF were of potential concern 
and could be evaluated further during the regulatory development 
process. 65 FR 79827. EPA also concluded that the remaining HAP 
evaluated in the Utility Study did not appear to be a public health 
concern, but the Agency noted that there were limited data and 
uncertainties associated with this conclusion, and we stated that 
future data collection efforts could identify additional HAP of 
potential concern. 65 FR 79827.
    EPA also explained that, consistent with Congress's direction in 
section 112(n)(1)(A), we considered the alternative control strategies 
available to control the HAP emissions that may warrant control. We 
noted that currently available controls for criteria pollutants would 
also be effective at controlling the HAP emissions from EGUs. 65 FR 
79828.
    EPA then made nine specific conclusions based on the information in 
the record, some of which are summarized above. 65 FR 79829-30. Based 
on those conclusions, EPA found that it was ``appropriate'' to regulate 
HAP emissions from coal- and oil-fired EGUs because EGUs ``are the 
largest domestic source of Hg emissions, and Hg in the environment 
presents significant hazards to public health and the environment.'' 65 
FR 79830. EPA noted that the NAS Study confirmed EPA's own research 
concluding that ``mercury in the environment presents a significant 
hazard to public health.'' 65

[[Page 24985]]

FR 79830. EPA explained that it was appropriate to regulate HAP 
emissions from coal- and oil-fired units because it had identified 
certain control options that, it anticipated, would effectively reduce 
HAP from such units. 65 FR 79830. In discussing its findings, EPA also 
noted that uncertainties remained concerning the extent of the public 
health impact from HAP emissions from oil-fired units. 65 FR 79830.
    Once EPA determined that it was ``appropriate'' to regulate coal- 
and oil-fired EGUs under CAA section 112, EPA next concluded that it 
was also ``necessary'' to regulate HAP emissions from such units 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 such emissions identified in the 
Utility RTC and confirmed by the NAS Study, and which section 112 is 
intended to address.'' 65 FR 79830.
    For natural gas-fired EGUs, EPA found that regulation of HAP 
emissions ``is not appropriate or necessary because the impacts due to 
HAP emissions from such units are negligible based on the results of 
the study documented in the utility RTC.'' 65 FR 79831.
    In light of the positive appropriate and necessary determination, 
EPA in December 2000 listed coal- and oil-fired EGUs on the section 
112(c) source category list. 65 FR 79831.
3. The 2005 Action
    On March 29, 2005, EPA issued the Section 112(n) Revision Rule 
(``2005 Action'') that has since been vacated by the DC Circuit Court. 
In that rule, EPA reversed the December 2000 Finding and concluded that 
it was neither appropriate nor necessary to regulate coal- and oil-
fired EGUs under section 112 and delisted such units from the section 
112(c) source category list. 70 FR 15994. EPA took the position that 
the December 2000 Finding lacked foundation and that new information 
confirmed that it was not appropriate or necessary to regulate coal- 
and oil-fired EGUs under CAA section 112.
    In the final rule, EPA provided a detailed interpretation of 
section 112(n)(1)(A), including the terms ``appropriate'' and 
``necessary,'' as those terms relate to the regulation of EGUs under 
section 112. In interpreting the statute, EPA recognized that section 
112(n)(1)(A) provided no explicit guidance for determining whether 
regulation of EGUs is appropriate and necessary. As such, EPA concluded 
that Congress' direction on the Utility Study provided the only 
guidance about the substance of the appropriate and necessary finding. 
Accordingly, EPA extrapolated from Congress' description of the Utility 
Study when interpreting the terms appropriate and necessary.
    Among other things, the Agency interpreted the focus on public 
health in the Utility Study as precluding EPA from considering 
environmental impacts. 70 FR 15998. EPA also looked at Congress' focus 
on EGU emissions in the Study and took the position that EPA could only 
consider hazards to public health that could be traced directly to HAP 
emissions from EGUs in assessing whether it was appropriate to 
regulate. EPA declined to consider the potential adverse public health 
impacts that may occur as the result of the combination of EGU HAP 
emissions and HAP emissions from other sources. 70 FR 15998.
    In making the determination as to whether it was appropriate to 
regulate, EPA analyzed whether the level of HAP emissions from EGUs 
remaining after imposition of the requirements of the CAA would result 
in a hazard to public health. EPA concluded that if the HAP emissions 
remaining after imposition of the requirements of the CAA do not pose a 
hazard to public health, then regulation under section 112 is not 
appropriate. EPA also maintained that even if it identified a hazard to 
public health, regulation may still not be ``appropriate'' based on 
other relevant factors, such as the cost effectiveness of regulation 
under section 112. 70 FR 15600.
    In the 2005 Action, EPA interpreted the term ``necessary'' to mean 
``that it is necessary to regulate EGUs under section 112 only if there 
are no other authorities available under the CAA that would, if 
implemented, effectively address the remaining HAP emissions from 
EGUs.'' 70 FR 16001.
    Applying these interpretations, the Agency stated that it was 
neither appropriate nor necessary to regulate HAP emissions from EGUs. 
The Agency took the position that the December 2000 appropriate finding 
lacked foundation because the finding was overbroad to the extent that 
it relied on environmental effects. 70 FR 16002. The EPA next stated 
that the appropriate determination in the December 2000 Finding lacked 
foundation because EPA did not fully consider the Hg reductions that 
would result after imposition of the requirements of the CAA and that 
new information showed that the level of Hg emissions from EGUs 
remaining after imposition of the requirements of the CAA do not pose a 
hazard to public health. 70 FR 16003-4. Specifically, EPA pointed to 
the promulgation of the Clean Air Interstate Rule (CAIR), issued 
pursuant to CAA section 110(a)(2)(D), and the Clean Air Mercury Rule 
(CAMR),\8\ issued pursuant to section 111, and, based on modeling, 
determined that CAIR, and independently CAMR, could be expected to 
reduce Hg emissions to levels that would not cause a hazard to public 
health. Therefore, EPA concluded that it was not appropriate to 
regulate EGUs under section 112. We note that CAMR was vacated by the 
D.C. Circuit Court in New Jersey v. EPA, and that CAIR was remanded to 
the Agency in North Carolina v. EPA, 531 F.3d 896, modified on reh'g, 
550 F.3d 1176 (DC Cir. 2008).
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    \8\ On May 18, 2005, EPA issued the Clean Air Mercury Rule 
(CAMR). 70 FR 28606. That rule established standards of performance 
for emissions of mercury from new and existing coal-fired EGUs 
pursuant to CAA section 111.
---------------------------------------------------------------------------

    As to the necessary finding, EPA took the position that the 
December 2000 Finding was in error because EPA did not, at the time, 
examine whether there were any CAA provisions other than section 112 
that, if implemented, would address any identified hazards to public 
health from HAP emissions from EGUs. 70 FR 16004. Specifically, EPA 
stated that the error existed because EPA did not consider CAA sections 
110(a)(2)(D) and 111 and that, considering actions under these 
sections, hazard to public health from EGUs would be reduced. 70 FR 
16005.
    EPA also determined that it was not appropriate and necessary to 
regulate coal-fired EGUs on the basis of non-Hg HAP emission or oil-
fired EGUs on the basis of Ni and non-Ni HAP. 70 FR 16007.
4. Litigation History
    Shortly after issuance of the December 2000 Finding, an industry 
group challenged that finding in the DC Circuit Court. UARG v. EPA, 
2001 WL 936363, No. 01-1074 (DC Cir. July 26, 2001). The DC Circuit 
Court dismissed the lawsuit holding that it did not have jurisdiction 
because 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.'' (emphasis added)
    Environmental groups, States, and tribes challenged the 2005 Action 
and CAMR. Among other things, the environmental and state petitioners 
argued that EPA could not remove EGUs

[[Page 24986]]

from the section 112(c) source category list without following the 
requirements of section 112(c)(9).
    On February 8, 2008, the DC Circuit Court vacated both the 2005 
Action and CAMR. The DC Circuit Court held that EPA failed to comply 
with the requirements of section 112(c)(9) for delisting source 
categories. Specifically, the DC Circuit Court held that section 
112(c)(9) applies to the removal of ``any source category'' from the 
section 112(c) list, including EGUs. The DC Circuit Court rejected the 
argument that EPA has the inherent authority to correct its mistakes, 
finding that, by enacting section 112(c)(9), Congress limited EPA's 
discretion to reverse itself and remove source categories from the 
section 112(c) list. The DC Circuit Court found that EPA's contrary 
position would ``nullify Sec.  112(c)(9) altogether.'' New Jersey, 517 
F.3d at 583. The DC Circuit Court did not reach the merits of 
petitioners' arguments on CAMR, but vacated CAMR for existing sources 
because coal-fired EGUs were listed sources under section 112. The DC 
Circuit Court reasoned that even under EPA's own interpretation of the 
CAA, regulation of existing sources' Hg emissions under section 111 was 
prohibited if those sources were a listed source category under section 
112.\9\ The DC Circuit Court vacated and remanded CAMR for new sources 
because it concluded that the assumptions EPA made when issuing CAMR 
for new sources were no longer accurate (i.e., that there would be no 
section 112 regulation of EGUs and that the section 111 standards would 
be accompanied by standards for existing sources). Id. at 583-84. Thus, 
CAMR and the 2005 appropriate and necessary finding became null and 
void.
---------------------------------------------------------------------------

    \9\ 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 section 111(d) for any HAP 
emitted from a particular source category, if the source category is 
regulated under section 112.
---------------------------------------------------------------------------

    On December 18, 2008, several environmental and public health 
organizations (``Plaintiffs'') \10\ filed a complaint in the DC 
District Court (Civ. No. 1:08-cv-02198 (RMC)) alleging that the Agency 
had failed to perform a nondiscretionary duty under CAA section 
304(a)(2), by failing to promulgate final 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 section 
112(c). EPA settled that litigation. The consent decree resolving the 
case requires EPA to sign a notice of proposed rulemaking setting forth 
EPA's proposed section 112(d) emission standards for coal- and oil-
fired EGUs by March 16, 2011, and a notice of final rulemaking by 
November 16, 2011.
---------------------------------------------------------------------------

    \10\ 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.
---------------------------------------------------------------------------

III. Appropriate and Necessary Finding

    As required by the CAA, we determined in December 2000, and confirm 
that finding here, that it is appropriate to regulate emissions of Hg 
and other HAP from EGUs because manmade emissions of those pollutants 
pose hazards to public health and the environment, and EGUs are the 
largest or among the largest contributors of many of those HAP. It is 
necessary to do so for a variety of reasons, including that hazards to 
public health and the environment from EGUs remain after imposition of 
the requirements of the CAA.
    In this section, we address the Agency's determination that it is 
appropriate and necessary to regulate coal- and oil-fired EGUs under 
CAA section 112. We first provide our interpretation of the critical 
terms in CAA section 112(n)(1). As shown below, these interpretations 
are wholly consistent with the CAA and the December 2000 Finding. We 
then demonstrate that the December 2000 Finding was valid at the time 
it was made based on the information available to the Agency at that 
time. Finally, we explain that, although not required, we recently 
conducted additional technical analyses given that several years have 
passed since the December 2000 Finding was issued. Those analyses 
include both a quantitative and qualitative assessment of the hazards 
to public health and a qualitative analysis of hazards to the 
environment associated with Hg and non-Hg HAP from EGUs. The analyses 
confirm that it remains appropriate and necessary today to regulate 
EGUs under CAA section 112. We also explain why these analyses and the 
other information currently before the Agency confirm that regulation 
of EGUs under section 112 is appropriate and necessary. Accordingly, 
such units are properly listed pursuant to section 112(c).

A. Regulating EGUs Under CAA Section 112

    CAA section 112(n)(1)(A) requires the Agency to regulate EGUs under 
section 112 ``if the Administrator finds such regulation is appropriate 
and necessary after considering the results of the [Utility Study].'' 
(emphasis added). Congress did not define the phrase ``appropriate and 
necessary'' in section 112(n)(1)(A). Rather, Congress expressly 
delegated to the Agency the authority to interpret and apply those 
terms. See Chevron U.S.A. Inc. v. Natural Resources Defense Council, 
Inc., 467 U.S. 837, 843-44 (1984) (the Agency's interpretation of 
statutory terms is entitled to considerable deference as long as it is 
a reasonable reading of the statute).
    Courts have interpreted the terms ``appropriate'' and ``necessary'' 
in other provisions of the CAA and other statutes, and concluded that 
those terms convey upon the Agency a wide degree of discretion. See, 
e.g., National Association of Clean Air Act Agencies v. EPA, 489 F.3d 
1221, 1229 (DC Cir. 2007) (finding ``both explicit and extraordinarily 
broad'' the Administrator's authority under CAA section 231(a)(3) to 
``issue regulations with such modifications as he deems appropriate.'') 
(emphasis in original); see also Cellular Telecommunications & Internet 
Association, et al. v. FCC, 330 F.3d 502, 510 (DC Cir. 2003), (finding 
that ``[c]ourts have frequently interpreted the word `necessary' to 
mean less than absolutely essential, and have explicitly found that a 
measure may be `necessary' even though acceptable alternatives have not 
been exhausted.'' (quoting Natural Res. Def. Council v. Thomas, 838 
F.2d 1224, 1236 (DC Cir. 1998) (internal quotation marks omitted)).
    We evaluate the terms ``appropriate'' and ``necessary'' within the 
statutory context in which they appear to determine the meaning of the 
words. See Cellular Telecommunications, 330 F.3d at 510 (finding that 
``it is crucial to understand the context in which the word [necessary] 
is used in order to comprehend its meaning.'') (citations omitted). In 
this case, we look for guidance in section 112 generally, and focus 
specifically on section 112(n)(1), which addresses EGUs.
1. Statutory Framework for Evaluating EGUs
    As explained above, Congress, concerned by the slow pace of EPA's 
regulation of HAP, ``altered section 112 by eliminating much of EPA's 
discretion in the process.'' New Jersey, 517 F.3d at 578 (citations 
omitted). We describe above the two-phased approach to standard 
setting. Also, relevant, however, is that Congress set very strict 
deadlines for listing source categories and issuing emission standards 
for such

[[Page 24987]]

categories. See e.g., Section 112(c)(6), 112(e)(1); New Jersey, 517 
F.3d at 578 (noting that ``EPA was required to list and to regulate, on 
a prioritized schedule'' all categories and subcategories of major and 
area sources). Thus, in substantially amending section 112 of the CAA 
in 1990, Congress sought prompt and permanent reductions of HAP 
emissions from stationary sources--first through technology-based 
standards, and then further, as necessary, through risk-based standards 
designed to protect human health and the environment.
    Congress' focus on protecting public health and the environment 
from EGU HAP emissions is reflected in section 112(n)(1), titled 
``[e]lectric utility steam generating units.'' That section directs EPA 
to evaluate HAP emissions from EGUs. In addition to directing EPA to 
regulate EGUs under section 112 if it determines that it is appropriate 
and necessary to do so, section 112(n)(1) requires the completion of 
three studies related to HAP emissions from EGUs. Those studies 
include: (1) The Utility Study pursuant to section (n)(1)(A); (2) the 
Mercury Study pursuant to section (n)(1)(B); and (3) the NIEHS Study 
(NAS Study) pursuant to section 112(n)(1)(C).\11\
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    \11\ As explained above, the NAS Study studied the same issues 
Congress wanted addressed pursuant to section 112(n)(1)(C) and, 
because it was conducted five years after the NIEHS study, it was a 
more comprehensive study accounting for new information not 
available to NIEHS. Congress directed both studies and wanted EPA to 
consider the NAS Study before issuing the appropriate and necessary 
finding so we are reasonably focusing our discussion on the content 
of the later study.
---------------------------------------------------------------------------

    These studies are described above, in detail. In summary, for the 
Utility Study, Congress required EPA to evaluate the hazards to public 
health that are reasonably anticipated to occur as the result of EGU 
emissions following imposition of the requirements of the CAA. Congress 
also directed EPA to identify alternative control strategies for those 
HAP that may warrant regulation under section 112.
    The Mercury Study required by section 112(n)(1)(B) is both broader 
and narrower in scope, as compared to the Utility Study. For example, 
the Mercury Study is narrower in scope, in that it focuses solely on 
the impacts from Hg emissions, as opposed to all HAP. The Mercury Study 
is broader in scope, however, in two important respects. First, 
Congress required EPA to consider environmental effects in addition to 
health effects. Second, Congress required the Agency to consider the 
cumulative effects of Hg from all sources, including EGUs. In 
considering the cumulative effects of Hg, the Agency was not required 
to apportion the cause of any adverse effects among the various sources 
of Hg. Both the Utility and Mercury Studies considered the control 
technologies available to control Hg emissions, but only the Mercury 
Study called for the evaluation of the costs of such controls. Section 
112(n)(1)(B).
    EPA believes that Congress directed the Agency to conduct the 
Utility Study so that the Agency would understand the hazards to public 
health posed by HAP emissions from EGUs alone, and consider whether any 
hazards that were identified would be addressed through imposition of 
the requirements of the CAA applicable to EGUs at that time. Congress 
provided EPA an additional year to examine the impacts of EGU emissions 
of Hg on health and the environment in combination with other sources 
of Hg emissions.
    The NAS Study required by section 112(n)(1)(C), which was due at 
the same time as the Utility Study, was to focus on Hg only and the 
adverse human health effects associated with Hg. The statute directed 
the determination of the threshold level of Hg below which adverse 
effects to human health are not expected to occur. The statute further 
directed the determination of the threshold for Hg concentrations in 
the tissue of fish which may be consumed, including by sensitive 
populations, without adverse effects to public health. Here, unlike the 
Utility Study and the Mercury Study, the statute specifically requires 
an evaluation of the adverse human health effects of Hg on sensitive 
populations.
    The remaining critical element of section 112(n)(1) is the 
direction to EPA to determine whether it is appropriate and necessary 
to regulate EGUs under section 112, considering the results of the 
Utility Study. Although the Utility Study is a condition precedent to 
making the appropriate and necessary determination, nothing in section 
112(n)(1)(A) precludes the Agency from considering other information in 
making that determination.
    Taken together, we believe these provisions provide a framework for 
the Agency's determination of whether to regulate HAP emissions from 
EGUs under section 112. Through these provisions, Congress sought a 
prompt review and evaluation of the hazards to public health and the 
environment associated with Utility HAP emissions. This prompt 
consideration of health and environmental impacts is consistent with 
the strict deadlines Congress imposed in section 112 on all other 
source categories. See infra.
    Section 112(n)(1)(B) is direct evidence that Congress was concerned 
with environmental effects and cumulative impacts of HAP emissions from 
EGUs and other sources, particularly with regard to the bio-
accumulative HAP Hg. Section 112(n)(1)(C) provides further evidence 
that Congress was concerned with limiting HAP emissions from EGUs to a 
level that protects sensitive populations. We believe the scope of the 
Utility Study was limited to HAP emissions from EGUs and hazards to 
public health, not because Congress was unconcerned with adverse 
environmental effects or the cumulative impact of HAP emissions, but 
because the Utility Study, as required, was a significant undertaking 
in itself and Congress wanted the Agency to complete the study within 3 
years. Thus, section 112(n)(1) reveals, among other things, Congress' 
concern for the health and environmental effects of HAP emissions from 
EGUs, both alone and in conjunction with other sources, the impact of 
Hg emissions from EGUs, and the availability of controls to address HAP 
emissions from EGUs.
    Finally, significantly, nowhere in section 112(n)(1) does Congress 
require the consideration of costs in assessing health and 
environmental impacts. The only reference to costs is in section 
112(n)(1)(B) and that reference required the Agency to consider the 
costs of emission reduction controls for Hg.
2. Interpretation of Key Terms
    Section 112(n)(1)(A) itself provides no clear standard to govern 
EPA's analysis and determination of whether it is ``appropriate and 
necessary'' to regulate utilities under section 112. The statute simply 
requires EPA to regulate EGUs under section 112 if it determines that 
such regulation is appropriate and necessary, after considering the 
results of the Utility Study. As noted above, courts have interpreted 
the terms appropriate and necessary as conveying considerable 
discretion to the Agency in determining what is appropriate and 
necessary in a given context.
    As explained more fully below, in this context, we interpret the 
statute to require the Agency to find it appropriate to regulate EGUs 
under CAA section 112 if the Agency determines that the emissions of 
one or more HAP emitted from EGUs pose an identified or potential 
hazard to public health or the environment at the time the finding is 
made. If the Agency finds that it is appropriate to regulate, it must 
find it necessary to regulate EGUs under section 112 if the identified 
or potential hazards to public health or the environment will not be 
adequately addressed by the imposition of the requirements of the CAA. 
Moreover, it

[[Page 24988]]

may be necessary to regulate utilities under section 112 for a number 
of other reasons, including, for example, that section 112 standards 
will assure permanent reductions in EGU HAP emissions, which cannot be 
assured based on other requirements of the CAA.
    The following subsections describe in detail our interpretation of 
the key statutory terms. We also explain below how the interpretations 
set forth in this notice are wholly consistent with the December 2000 
Finding. Further, to 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. See National Cable & Telecommunications Ass'n, et al. v. 
Brand X Internet Services, et al., 545 U.S. 967, 981 (2005) (Discussing 
the deference provided to an Agency when 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); see also Department of Treasury v. FLRA, 494 U.S. 
922, 933 (1990) (Finding that EPA's judgment should only be overturned 
if it is deemed unreasonable, not merely because other, reasonable 
alternatives exist).
a. ``Appropriate'' To Regulate EGUs
    We interpret section 112(n)(1)(A) to require the Agency to find 
regulation of EGUs under section 112 appropriate if we determine that 
HAP emissions from EGUs pose a hazard to public health or the 
environment at the time the finding is made. The hazard to public 
health or the environment may be the result of HAP emissions from EGUs 
alone or the result of HAP emissions from EGUs in conjunction with HAP 
emissions from other sources. In addition, EPA must find that it is 
appropriate to regulate EGUs if it determines that any single HAP 
emitted by utilities poses a hazard to public health or the 
environment. We further interpret the term ``appropriate'' to not allow 
for the consideration of costs in assessing whether HAP emissions from 
EGUs pose a hazard to public health or the environment. Finally, we may 
conclude that it is appropriate, in part, to regulate EGUs if we 
determine that there are controls available to address HAP emissions 
from EGUs.
i. Basis for Interpretation
    As stated above, the appropriate finding may be based on hazards to 
public health or the environment. Although we believe that Congress' 
primary concern, as expressed in section 112(n)(1)(A) and 112(n)(1)(C), 
related to hazards to public health, the inclusion of environmental 
effects in section 112(n)(1)(B) indicates Congress' interest in 
protecting the environment from HAP emissions from EGUs as well.
    Moreover, the term ``appropriate'' is extremely broad and nothing 
in the statute suggests that the Agency should ignore adverse 
environmental effects in determining whether to regulate EGUs under 
section 112. Further, had Congress intended to prohibit EPA from 
considering adverse environmental effects in the ``appropriate'' 
finding, it would have stated so expressly. Absent clear direction to 
the contrary, and considering the purpose of the CAA (see e.g., CAA 
section 101, 112(c)(9)(B)(ii)), it is reasonable to consider 
environmental effects in evaluating the hazards posed by HAP emitted 
from EGUs when assessing whether regulation of EGUs under section 112 
is appropriate. Accordingly, we interpret the statute to authorize the 
Agency to base the appropriate finding on either hazards to public 
health or the environment.
    We also maintain that the Agency should base its ``appropriate'' 
evaluation on the hazards to public health or the environment that 
exist at the time the determination is made, not after considering the 
imposition of the other requirements of the CAA. The Agency evaluates 
whether imposition of the requirements of the CAA will adequately 
address any identified hazards only in the context of the necessary 
finding. Thus, in assessing whether regulation of EGUs is appropriate 
under section 112, we evaluate the current hazards posed by such units, 
as opposed to projecting what such hazards may look like after 
imposition of the requirements of the CAA.
    We further interpret the CAA as allowing the Agency to base the 
appropriate finding on hazards to public health or the environment that 
result from HAP emissions from EGUs alone or hazards to public health 
and the environment that result from HAP emissions from EGUs in 
conjunction with HAP emissions from other sources. Section 112(n)(1) 
does not focus exclusively on EGU-only HAP emissions.
    As explained above, section 112(n)(1)(B) and (C) require either 
expressly or implicitly the consideration of Hg emissions from all 
sources, not just EGUs. Section 112(n)(1)(B) is of note because that 
provision does not require the Agency to determine the hazard posed by 
Hg from EGUs alone. Rather, Congress required EPA to evaluate the 
health and environmental effects of Hg emissions from ``electric 
utility steam generating units, municipal waste combustion units, and 
other sources, including area sources.'' Section 112(n)(1)(C) is also 
relevant because it requires a human health-based assessment of the 
hazards posed by Hg without regard to the origin of the Hg. Congress 
could have directed an evaluation of the human health risk attributable 
to EGUs alone, but it did not. Congress also did not require such an 
assessment be conducted in the NAS Study.
    In addition, Congress directed the Agency in section 112(n)(1)(A) 
to regulate EGUs under section 112 if the results of the Utility Study 
caused the Agency to conclude that regulation was appropriate and 
necessary. Section 112(n)(1)(A) is not written in a manner to preclude 
consideration of other information when determining whether it is 
appropriate and necessary to regulate EGUs under section 112, and that 
includes consideration of all hazards, both health and environmental, 
posed by HAP emitted by EGUs. See United States v. United Technologies 
Corp., 985 F.2d 1148, 1158 (2d Cir. 1993) (``based upon'' does not mean 
``solely'').
    Finally, focusing on HAP emissions from EGUs alone when making the 
appropriate finding ignores 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 that harm. For this reason, we believe we 
may consider the hazards to public health and the environment posed by 
HAP emissions from EGUs alone or in conjunction with HAP emissions from 
other sources.
    Furthermore, the appropriate finding may be based on a finding that 
any single HAP emitted from EGUs poses a hazard to public health or the 
environment. Nothing in 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 section 112. Interpreting the statute in this 
manner would preclude the Agency from addressing under section 112 
identified or potential hazards to public health or the environment 
associated with HAP emissions from EGUs unless

[[Page 24989]]

we found a hazard existed with respect to each and every HAP emitted.
    Indeed, Congress' focus in section 112(n)(1)(B) and (C) on Hg 
indicates Congress' awareness that Hg was a problem and supports the 
position that EPA could find it appropriate to regulate EGUs based on 
the adverse health and environmental effects of a single HAP. 
Furthermore, the statute does not directly or expressly authorize the 
Agency to regulate only those HAP for which a hazard finding has been 
made. In fact, the statute requires the Agency to regulate EGUs under 
section 112 if the Agency finds regulation under section 112 is 
appropriate and necessary, and regulation under section 112 for major 
sources requires MACT standards for all HAP emitted from the source 
category. See, e.g., National Lime Ass'n v. EPA, 233 F.3d 625, 633 (DC 
Cir. 2000). For these reasons, we conclude we must find it appropriate 
to regulate EGUs under section 112 if we determine that the emissions 
of any single HAP from such units pose a hazard to public health or the 
environment.
    We also maintain that the better reading of the term 
``appropriate'' is that it does not allow for the consideration of 
costs in assessing whether hazards to public health or the environment 
are reasonably anticipated to occur based on EGU emissions. Had 
Congress intended to require the Agency to consider costs in assessing 
hazards to public health or the environment associated with EGU HAP 
emissions, it would have so stated.
    This interpretation is consistent with the overall structure of the 
CAA. Congress did not authorize the consideration of costs in listing 
any source categories for regulation under section 112. In addition, 
Congress did not permit the consideration of costs in evaluating 
whether a source category could be delisted pursuant to the provisions 
of section 112(c)(9).
    Under section 112(n)(1)(A), EPA is evaluating whether to regulate 
HAP emissions from EGUs at all. It is reasonable to conclude that costs 
may not be considered in determining whether to regulate EGUs under 
section 112 when hazards to public health and the environment are at 
issue.
    Finally, consistent with sections 112(n)(1)(A) and 112(n)(1)(B), we 
conclude that we may base the appropriate finding on the availability 
of controls to address HAP emissions from EGUs.
ii. The December 2000 Finding
    The Agency's interpretation of the term ``appropriate,'' as set 
forth above, is wholly consistent with the Agency's appropriate finding 
in December 2000. As noted above, in 2000, we concluded that it was 
appropriate to regulate EGUs under section 112 because Hg in the 
environment posed a hazard to public health and the environment. The 
Agency also concluded it was appropriate because of uncertainties 
associated with the hazards posed by other HAP emitted from EGUs. 65 FR 
79827. Finally, the EPA concluded that it was appropriate because of 
the availability of controls to reduce HAP emissions from EGUs. In 
making the finding as it related to Hg, the Agency considered the 
hazards posed by Hg in the environment and the contribution of EGUs to 
that hazard. In addition, EPA did not consider costs when making the 
appropriate determination. Further, the appropriate finding evaluated 
the hazards at the time, as opposed to the hazards remaining after 
imposition of the requirements of the CAA. EPA evaluated whether the 
other requirements of the CAA would adequately address the hazards in 
the necessary prong only.\12\
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    \12\ As explained below, EPA reasonably concluded in December 
2000 that it was appropriate and necessary to regulate EGUs under 
section 112 based on the record before the Agency at that time.
---------------------------------------------------------------------------

iii. The 2005 Action
    As noted above, in 2005, EPA revised its December 2000 Finding and 
stated that the appropriate finding: (1) Could not be based on adverse 
environmental effects; (2) must be made considering only HAP emissions 
from EGUs; (3) must be made after consideration of the imposition of 
the requirements of the CAA; and (4) must consider other factors (e.g., 
costs) even if we determine that HAP emissions from EGUs pose a hazard 
to public health. This proposal differs from the 2005 Action, and we 
address each of these differences below.
    First, we change the position taken in 2005 that the appropriate 
finding could not be based on environmental effects alone. In 2005, we 
did not properly consider all of the provisions of section 112(n)(1). 
The Agency should not interpret the CAA to limit the Agency's 
discretion to protect the environment absent clear direction to that 
effect. In essence, the Agency's interpretation in 2005 would have 
required the Agency to ignore a catastrophic environmental harm (e.g., 
the extinction of a species) if the Agency could not also identify a 
hazard to public health. EPA took this position regarding environmental 
effects in 2005 even though in that same rule it correctly interpreted 
section 112(n)(1)(A) to allow the Agency to consider information beyond 
the Utility Study in making the appropriate and necessary 
determination. 70 FR 15,997-99. The 2005 interpretation that EPA cannot 
consider environmental effects in evaluating whether it is appropriate 
to regulate EGUs under section 112 was neither reasonable nor 
consistent with the goals of the CAA, and, therefore, we are rejecting 
that interpretation and returning to the approach taken in 2000 that 
allowed consideration of environmental effects.
    Second, for all of the reasons stated above, we are revisiting the 
2005 interpretation that required the Agency to consider HAP emissions 
from EGUs without considering the cumulative impacts of all sources of 
HAP emissions. Nothing in section 112(n)(1)(A) prohibits consideration 
of HAP emissions from EGUs in conjunction with HAP emissions from other 
sources of HAP. We believe it is more reasonable to interpret the 
statute to authorize the Agency to consider the cumulative effects of 
HAP that are emitted from EGUs and other sources. This interpretation 
allows the Agency to evaluate more fully whether HAP emissions from 
EGUs pose a hazard to public health or the environment consistent with 
the manner in which the public and the environment are exposed to HAP 
emissions.
    Third, we are revising the 2005 interpretation that required the 
Agency to evaluate the hazards to public health after imposition of the 
requirements of the CAA. We conclude today that in 2005 the Agency 
improperly conflated the appropriate finding and the necessary finding 
by requiring consideration of the ameliorative effects of other CAA 
requirements in both prongs of the appropriate and necessary finding. 
We believe the Agency must find it appropriate to regulate EGUs under 
section 112 if we determine that HAP emitted by EGUs pose a hazard to 
public health or the environment at the time the finding is made. The 
issue of how and whether those hazards are reduced after imposition of 
the requirements of the CAA is an issue for the necessary prong of the 
finding.
    Finally, we are rejecting the 2005 interpretation that authorizes 
the Agency to consider other factors (e.g., cost), even if the Agency 
determines that HAP emitted by EGUs pose a hazard to public health (or 
the environment). We reject the consideration of costs for all the 
reasons set forth above. Furthermore, the better reading of section 
112(n)(1)(A) is that the Agency should find it appropriate to regulate 
EGUs under section 112 if a hazard to public health or the environment 
is identified. We think it

[[Page 24990]]

unreasonable to decline to make the appropriate finding based on any 
factor, cost or otherwise, if we determine that EGUs pose a hazard to 
public health or the environment.
b. ``Necessary'' To Regulate EGUs
    Once the Agency has determined that it is appropriate to regulate 
EGUs under section 112, the Agency must then determine whether it is 
necessary to regulate EGUs under section 112. As stated above, we have 
considerable discretion to determine whether regulation of EGUs under 
section 112 is necessary. The DC Circuit Court 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.'' Cellular 
Telecommunication, 330 F.3d at 510.
    If the Agency concludes that it is appropriate to regulate EGUs, we 
believe it is necessary to regulate HAP emissions from EGUs if we 
determine that the imposition of the requirements of the CAA will not 
sufficiently address the identified hazards to public health or the 
environment posed by HAP that are emitted from EGUs. We maintain that 
we must find it necessary based on such a finding even if regulation 
under section 112 will not fully resolve the identified hazard to 
public health or the environment.
    We may also determine it is necessary to regulate under section 112 
if we are uncertain whether the imposition of the other requirements of 
the CAA will sufficiently address the identified hazards. We may find 
it necessary to regulate EGUs under section 112 even if we were to 
conclude, based on reasonable estimations of emissions reductions, that 
the imposition of the other requirements of the CAA would, or might, 
significantly reduce the identified hazard, because the only way to 
guarantee that such reductions will occur at all EGUs and be maintained 
is through a section 112(d) standard that directly regulates HAP 
emissions from utilities. Finally, we may also find it necessary to 
regulate EGUs under section 112 to further the policy goal of 
supporting international efforts to reduce HAP emissions, including Hg.
i. Necessary After Imposition of the Requirements of the CAA
    In the Utility Study, Congress directed the Agency to evaluate the 
hazards to public health posed by HAP emissions from EGUs remaining 
after imposition of the requirements of the CAA, and it gave EPA 3 
years to complete that Study. We interpret the necessary requirement 
first in the context of the phrase ``after imposition of the 
requirements of [the CAA].'' Section 112(n)(1)(A).
    Congress did not define the phrase ``after imposition of the 
requirements of the Act.'' The plain meaning of the term 
``requirement'' is something that is necessary, or obligatory. See, 
e.g., Random House Webster's Unabridged Dictionary, Deluxe Edition, 
2001. Given that Congress intended the Utility Study to be completed by 
1993, it is reasonable to interpret the phrase ``after imposition of 
the requirements of the Act'', as requiring the Agency to consider only 
those requirements that Congress directly imposed on EGUs through the 
CAA as amended in 1990 and for which EPA could reasonably predict HAP 
emission reductions at the time of the Utility Study. The most 
substantial requirement in this regard was the newly enacted ARP.
    The purpose of the ARP was to reduce the adverse effects of acid 
deposition (more commonly known as ``acid rain''), by limiting the 
allowable emissions of SO2 and NOX primarily from 
EGUs. In enacting the Acid Rain provisions of the Act, Congress 
explained that the problem of acid deposition was one of ``national and 
international significance,'' that technologies to reduce the 
precursors to acid deposition were ``economically feasible,'' and that 
``control measures to reduce precursor emissions from steam-electric 
generating units should be initiated without delay.'' CAA section 
401(a). The ARP also includes a series of very specific emission 
reduction requirements. For example, the goals of the program include a 
reduction of annual SO2 emissions by 10 million tons below 
1980 levels and a reduction of NOX emissions by two million 
tons from 1980 levels.
    Moreover, the ARP achieved the required reductions by allocating 
allowances to emit SO2 at reduced levels to each affected 
EGU. Sources were prohibited from emitting more SO2 than the 
number of allowances held. To comply with these requirements, source 
owners or operators could elect to install controls, such as scrubbers, 
switch to lower sulfur fuels at their facilities, or purchase 
allowances from other EGUs that had reduced their emissions beyond what 
they were required by the ARP to achieve. It was known at the time of 
enactment of the 1990 Amendments that the controls used to reduce 
emissions of SO2, primarily scrubbers, had the co-benefit of 
controlling HAP emissions, including Hg emissions. The ARP also 
included requirements for limiting NOX emissions from EGUs. 
Considering the Acid Rain requirements under section 112(n)(1) is 
reasonable because the Act contained very specific emission reduction 
requirements for EGUs, and a tight compliance time-frame. In fact, all 
of the regulations implementing the SO2 allowance trading 
portion of the ARP were completed by the mid-1990's.
    The other significant requirement that Congress imposed in the 1990 
Amendments was to revise the NSPS for NOX emissions from 
EGUs by 1994. CAA 407(c). However, unlike the SO2 allowance 
requirements of the ARP, Congress did not specify the amount of 
required reductions, but instead directed EPA to consider the 
improvements in methods for reducing NOX when establishing 
standards for new sources. Thus, in the 1990 Amendments, Congress 
sought NOX reductions from EGUs both through the ARP and a 
revision of the NSPS applicable to new sources. The Agency issued these 
NSPS in 1997.
    There are other requirements of Title I of the Act that could 
affect EGUs, and they include the National Ambient Air Quality 
Standards (NAAQS). Congress did not impose these provisions directly on 
EGUs, however. Instead, EPA is responsible for developing the NAAQS, 
and states are primarily responsible for assuring attainment and 
maintenance of the NAAQS. For example, EPA stated in the Utility Study 
that implementation of the 1997 NAAQS for ozone and PM may lead to 
reductions in Hg emissions, but those potential reductions could not be 
sufficiently quantified because states have the ultimate responsibility 
for implementing the NAAQS. See Utility Study, pages ES-25, 1-3, 2-32, 
3-14, and 6-15. States use a broad combination of measures (mobile and 
stationary) to obtain the reductions needed to meet the NAAQS. These 
decisions are unique to each state, as each state must identify and 
assess the sources contributing to nonattainment and determine how best 
to meet the NAAQS. EPA cannot predict with any certainty precisely how 
states will ensure that the reductions needed to meet the NAAQS will be 
realized. Moreover, there are additional uncertainties even were a 
state to impose requirements on EGUs through a State Implementation 
Plan (SIP), because each EGU may choose to meet the required reductions 
in a different manner, which could result in more or less HAP emission 
reductions. Accordingly, we do not believe it would have been 
appropriate to include such potential emissions reductions in 
determining whether it is necessary to

[[Page 24991]]

regulate HAP emissions from EGUs under section 112.
    Further, it is reasonable to interpret the phrase ``after 
imposition of the requirements of the Act'', as only requiring 
consideration of those requirements that Congress directly imposed on 
EGUs through the CAA as amended in 1990 and for which EPA could 
reasonably predict emission reductions at the time of the Utility 
Study. To interpret the phrase otherwise would require the Agency to 
look ahead two to three decades to forecast what possible requirements 
might be developed and applied to EGUs under some requirement of the 
CAA at some point in the future.
    Indeed, such an interpretation would be inconsistent with the 
structure and purpose of section 112. As noted above, Congress gave EPA 
until 1993 to issue the Utility Study and expected the appropriate and 
necessary finding would follow shortly thereafter. Congress also 
required EPA to address HAP emissions rapidly from all source 
categories. See CAA 112(e), supra. It is reasonable to presume that 
Congress intended EPA to evaluate the need for EGU HAP controls in 
light of the requirements imposed upon the industry via the new 1990 
requirements. Obviously the central requirement that was new and 
applied to EGUs was the ARP which would be implemented rapidly 
following passage of the 1990 amendments to the Act.
    Although the above represents a reasonable interpretation of what 
Congress contemplated the Utility Study would examine with regard to 
``imposition of the requirements of the Act,'' we recognize that we 
have discretion to look beyond the Utility Study in determining whether 
it is necessary to regulate EGUs under section 112. Given that several 
years have passed since the December 2000 Finding, we conducted 
additional analysis. Although not required, we conducted this analysis 
to demonstrate that even considering a broad array of diverse 
requirements, it remains appropriate and necessary to regulate EGUs 
under section 112.
    Specifically, we examined a host of requirements, which in our 
view, far surpass anything Congress could have contemplated in 1990 we 
would consider as part of our ``necessary'' determination. For example, 
our analysis includes certain state rules regulating criteria 
pollutants, Federal consent decrees, and settlement agreements for 
criteria pollutants resolving state-initiated and citizen-initiated 
enforcement actions.\13\ We did not include in our analysis any state-
only HAP requirements or voluntary actions to reduce HAP emissions, as 
those are not requirements of the CAA, and are not required by Federal 
law to remain applicable.\14\
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    \13\ In our analysis, we included state requirements and citizen 
and state settlements associated with criteria pollutants because 
those requirements may have a basis under the CAA. We did not, 
however, conduct an analysis to determine whether that was the case 
in each instance. As such, we believe there may be instances where 
we should not have considered certain state rules or state and 
citizen suit settlements in our analysis, because those requirements 
are based solely in state law and are not required by Federal law.
    \14\ Although, as explained below, our technical analysis 
examined impacts projected out to 2016, this is a very conservative 
approach. Given that two decades have passed since the enactment of 
the 1990 CAA Amendments, we believe we can find it appropriate and 
necessary to regulate EGUs under section 112, if we determine EGU 
HAP emissions pose a hazard to public health and the environment 
today without considering future HAP emission reductions. Congress 
could not have contemplated in 1990 that EPA would have failed in 
2011 to have regulated HAP emissions from EGUs where hazards to 
public health and the environment remain.
---------------------------------------------------------------------------

ii. Necessary Interpretation
    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.
    Furthermore, we believe it is necessary to regulate if we have 
identified a hazard to public health or the environment that will not 
be addressed by imposition of the requirements of the CAA even if 
regulation of EGUs under section 112 will not fully resolve the 
identified hazard. We conclude that this is particularly true for bio-
accumulative HAP such as Hg because EPA can only address such emissions 
from domestic sources and mitigation of identified risks associated 
with such HAP is a reasonable goal. See section 112(c)(6). EPA cannot 
decline to find it ``necessary'' to regulate EGUs under section 112 
when it has identified a hazard to public health or the environment, 
simply because that regulation will not wholly resolve the identified 
hazards. The statute does not require the Agency to conclude that 
identified hazards will be fully resolved before it may find regulation 
under section 112 necessary. See Massachusetts v. EPA, 549 U.S. 497, 
525 (2007).
    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 final or are still subject to judicial review 
(i.e., the Transport Rule \15\). If such rules are either not finalized 
or upheld by the Courts, the level of risk would potentially increase.
---------------------------------------------------------------------------

    \15\ Federal Implementation Plans To Reduce Interstate Transport 
of Fine Particulate Matter and Ozone. Proposed Rule. August 2, 2010. 
75 FR 45,210.
---------------------------------------------------------------------------

    We also may find it necessary to regulate EGUs under section 112 
even if we conclude, based on reasonable estimations of emissions 
reductions, that the imposition of the other requirements of the CAA 
will significantly reduce the identified hazard. We maintain this is 
reasonable because the only way to guarantee that the necessary 
reductions in HAP emissions will occur at all EGUs and be maintained is 
through a section 112(d) standard that directly regulates HAP emissions 
from EGUs. This is true because sources could discontinue use of 
controls for criteria pollutants that achieve HAP reductions as a co-
benefit if new control technologies or practices are identified that 
reduce the relevant criteria pollutants but do not also reduce HAP. For 
example, scrubbers are often used to reduce SO2 emissions 
and those scrubbers also reduce emissions of several HAP. However, if 
an EGU with a scrubber started complying with its SO2 
standard by switching to low sulfur coal or purchasing allowances, the 
HAP

[[Page 24992]]

emission reduction co-benefits associated with the scrubber would no 
longer be realized. In addition, at the time Congress passed the 1990 
CAA amendments, there were many older EGUs that had few or no controls 
in place. Over 20 years later, there remain a significant number of 
older EGUs that are only minimally controlled. The Agency may find it 
necessary to regulate EGUs under section 112 to ensure that these 
minimally controlled EGUs and those units that switch to other criteria 
pollutant compliance options, thereby no longer achieving the same HAP 
reductions, are subject to HAP regulation, such that the estimated 
reductions in the identified hazards are realized.
iii. December 2000 Finding
    Our interpretation of the necessary finding is reasonable and 
consistent with the December 2000 Finding. In that finding, EPA 
determined that the imposition of the requirements of the CAA would not 
address the serious public health and environmental hazards resulting 
from EGU HAP emissions. We also stated that section 112 is the 
authority to address hazards from HAP emissions. Because we determined 
that the imposition of the requirements of the CAA would not address 
the identified hazards, we correctly concluded it was necessary to 
regulate under section 112. Although the Agency did not expressly 
interpret the term necessary in the December 2000 Finding, under the 
interpretation set forth above, the Agency must find it necessary if we 
conclude that the imposition of the other requirements of the CAA will 
not address the identified hazards. Because EPA reached that 
conclusion, the Agency correctly determined that it was necessary to 
regulate EGU HAP emissions and did not need to base the 2000 necessary 
finding on any of the other bases set forth above.
iv. The 2005 Action
    We stated in 2005 that ``it is necessary to regulate EGUs under 
section 112 only if there are no other authorities under the CAA that, 
if implemented, would effectively address the remaining HAP emissions 
from EGUs.'' 70 FR 16,001.\16\ In essence, we stated in 2005 that 
section 112(n)(1)(A) requires the Agency to scour the CAA to determine 
whether there is a direct or indirect manner in which EPA could 
regulate HAP emissions from EGUs, notwithstanding the fact that 
Congress expressly provided section 112 for the purpose of regulating 
HAP emissions from stationary sources. This interpretation is not 
reasonable.
---------------------------------------------------------------------------

    \16\ In the rule reconsidering the 2005 Action, we further 
clarified that in evaluating the effectiveness of other CAA 
authorities we considered whether those other authorities could be 
implemented in a cost-effective and administratively effective 
manner. 71 FR 33,391. We need not address this in detail because we 
conclude that the threshold conclusion that the Agency must look for 
alternative CAA authorities that could be used to regulate HAP 
emissions from EGUs before finding it necessary is invalid.
---------------------------------------------------------------------------

    Congress enacted section 112 for the express purpose of regulating 
HAP emissions. It is not reasonable to interpret section 112(n)(1)(A) 
to require the Agency to find another provision of the CAA to address 
identified hazards to public health or the environment. This is 
particularly the case where the Agency would not have certainty that 
such alternative legal theory would withstand judicial scrutiny because 
section 112 is the authority expressly provided to regulate HAP 
emissions and no other provision provides express authority to regulate 
HAP emissions from existing stationary sources.\17\ Although anyone can 
challenge the substance of a section 112 standard, no one can challenge 
that regulation of HAP emissions under section 112 is proper for 
validly listed source categories.
---------------------------------------------------------------------------

    \17\ In theory, an NSPS is legally permissible for new 
stationary sources of HAP.
---------------------------------------------------------------------------

    Furthermore, section 112(n)(1)(A) states explicitly that the Agency 
shall regulate EGUs ``under this section'' if the Agency determines it 
is ``appropriate and necessary after considering the results of the 
(Utility Study).'' We reiterate that the only precondition to 
regulating EGUs is consideration of the results of the Utility Study. 
We believe it is unreasonable to argue that Congress directed the 
Agency as part of the Utility Study to scour the CAA for alternative 
legal authorities for regulating HAP emissions, either directly or 
indirectly. Indeed, the Agency did not interpret the requirement in 
section 112(n)(1)(A) to conduct the study in that manner, as evidenced 
by the Utility Study itself. Absent that interpretation, we think it is 
unreasonable to conclude that the Agency must undertake such an effort 
to make the necessary finding because Congress authorized the Agency to 
base the ``appropriate and necessary'' finding on the Utility Study 
alone.
    For all the reasons above, we believe it is appropriate to regulate 
EGUs under section 112 if the Agency determines that HAP emissions from 
such units pose a hazard to public health or the environment at the 
time of the finding, and it is necessary to regulate EGUs under section 
112 if the imposition of the other requirements of the CAA will not 
adequately address the identified hazards to public health or the 
environment, or there are other compelling reasons making it necessary 
to regulate HAP emissions from EGUs under section 112.
c. Hazards to Public Health or the Environment
    Section 112(n)(1)(A) neither defines the phrase ``hazards to public 
health,'' nor sets forth parameters for EPA to use in determining 
whether HAP emissions from EGUs pose a hazard to public health. The 
phrase is also not defined elsewhere in the CAA. EPA, therefore, has 
broad discretion, using its technical and scientific expertise, to 
determine whether HAP emissions from EGUs pose a hazard to public 
health.
    In evaluating hazards to the environment, however, Congress did 
provide some direction. Specifically, it defined the term ``adverse 
environmental effects'' in section 112(a)(7), and as explained further 
below, we evaluate hazards to the environment consistent with that 
definition.
    Because Congress did not define ``hazard to public health'' the 
Agency must use its scientific and technical expertise to determine 
what constitutes a hazard to public health in the context of EGU HAP 
emissions. The Agency considers various factors in evaluating hazards 
to public health, including, but not limited to, the nature and 
severity of the health effects associated with exposure to HAP 
emissions; the degree of confidence in our knowledge of those health 
effects; the size and characteristics of the populations affected by 
exposures to HAP emissions; the magnitude and breadth of the exposures 
and risks posed by HAP emissions from a particular source category, 
including how those exposures contribute to risk in populations with 
additional exposures to HAP from other sources; and the proportion of 
the population exposed above benchmark levels of concern (e.g., cancer 
risks greater than 1 in a million or non-cancer effects with a hazard 
quotient (HQ) greater than 1). See Section III(D) below for a 
discussion of the Agency's technical conclusions as to whether a hazard 
to public health or the environment exists based on the facts at issue 
here.
    Although Congress provided no definition of hazard to public 
health, section 112(c)(9)(B) is instructive. In that section, Congress 
set forth a test for removing source categories from the section 112(c) 
source category list. That

[[Page 24993]]

test is relevant because it reflects Congress' view as to the level of 
health effects associated with HAP emissions that Congress thought 
warranted continued regulation under section 112. The Agency finds 
section 112(c)(9)(B)(i) particularly instructive because it provides a 
numerical threshold for HAP that may cause cancer. Specifically, that 
provision provides that EPA may delete a source category from the 
section 112(c) list if no source in the category emits such HAP 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 such HAP emissions. Thus, the Agency reads section 112(c)(9)(B)(i) 
to reflect Congress' view of the acceptable hazard to public health for 
HAP that may cause cancer.
    Congress defined the phrase ``adverse environmental effect'' in 
section 112(a)(7) to mean ``any significant and widespread adverse 
effect, which may reasonably be anticipated, to wildlife, aquatic life, 
or other natural resources, including adverse impacts on populations of 
endangered or threatened species or significant degradation of 
environmental quality over broad areas.''
    Section 112(n)(1)(B) required EPA to examine the environmental 
effects of Hg emissions. Because Congress defined the term ``adverse 
environmental effect'' in section 112(a)(7), we believe that such 
definition should guide our assessment of whether hazards to the 
environment posed by Utility HAP emissions exist. As with hazards to 
public health, however, the Agency must use its discretion to determine 
whether the adverse environmental effects identified warrant a finding 
that it is appropriate to regulate HAP emissions from EGUs based on 
those effects. In evaluating the environmental effects, we have stated 
that we may consider various aspects of pollutant exposure, including: 
``[t]oxicity effects from acute and chronic exposures'' expected from 
the source category (as measured or modeled); ``persistence in the 
environment;'' ``local and long-range transport;'' and ``tendency for 
bio-magnification with toxic effects manifest at higher trophic 
levels.'' 67 FR 44,718 (July 3, 2002).
    In interpreting the term itself, we believe the broad language in 
section 112(a)(7) referring to ``any'' enumerated effect ``which may be 
reasonably anticipated'' evinces Congressional intent to not restrict 
the scope of that term to only certain specific impacts. 62 FR 36440 
(July 7, 1997); 63 FR 14094 (March 24, 1998). Further, the section 
112(a)(7) reference to ``any'' enumerated effect in the singular 
clearly contemplates impacts of limited geographic scope, suggesting 
that the ``widespread'' criterion does not present a particularly 
difficult threshold to cross. Id. This is further supported by the fact 
that section 112(a)(7) provides as an example of adverse environmental 
effects, adverse impacts on populations of endangered or threatened 
species, which as reflective of their imperiled status are especially 
likely to exist in limited geographic areas. EPA believes that the 
``widespread'' criterion would not exclude impacts that might occur in 
only one region of the country. Id.
d. Regulating EGUs ``Under This Section''
    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., section 112(b)). The last 
sentence requires the Agency to regulate under this section (i.e., 
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., section 112(n)(1)(A)). The 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 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.
    Furthermore, the DC 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 
section 112. New Jersey, 517 F.3d at 583. Indeed, the DC 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, EPA is required to establish emission standards 
for EGUs consistent with the requirements set forth in section 112(d), 
as described above.
    EPA requests comment on section III.A.

B. The December 2000 Appropriate and Necessary Finding was Reasonable

    EPA reasonably determined in December 2000 that it was appropriate 
and necessary to regulate HAP emissions from EGUs under CAA section 
112. In making that finding, EPA considered all of the information that 
Congress had identified as most salient, including the Utility Study, 
the Mercury Study, and the information in the NAS Study.\18\ EPA even 
conducted an ICR soliciting emissions information on Hg, which was the 
HAP of most concern to Congress, as evidenced by section 112(n)(1). EPA 
collaborated further with a number of other entities and Federal 
Agencies, including the U.S. Department of Energy (DOE). EPA carefully 
evaluated all of this information, much of which had been the subject 
of extensive peer review, and reasonably determined, on the record 
before the Agency at the time, that it was appropriate and necessary to 
regulate EGUs under section 112.
---------------------------------------------------------------------------

    \18\ As explained above, we discuss the NAS Study here because 
it addressed the same issues as the NIEHS study, and it is the more 
recent study.
---------------------------------------------------------------------------

1. EPA Appropriately Based the Finding on the Information Required by 
Section 112(n)(1) and Reasonably Made the Finding Once It Had Completed 
the Required Studies
    In making the appropriate and necessary finding in 2000, EPA 
considered all of the relevant information in the three Studies 
required by section 112(n)(1) and the NAS Study. 65 FR 79826-27. The 
Utility, Mercury, and NAS Studies together consisted of thousands of 
pages of information and technical analyses. All of these studies were 
peer reviewed prior to issuance. In fact, the Mercury Study was 
reviewed by over 65

[[Page 24994]]

independent scientists.\19\ The NAS Study contains a thorough technical 
discussion summarizing the state of the science at the time regarding 
the human health effects of MeHg.
---------------------------------------------------------------------------

    \19\ Mercury Study Report to Congress, Vol. I, Pg. 6, December 
1997.
---------------------------------------------------------------------------

    In addition to conducting the studies that Congress required, EPA 
collected relevant information on Hg emissions and available control 
technologies. Specifically, pursuant to a CAA section 114 ICR, EPA 
collected data on the Hg content in coal from all coal-fired EGUs for 
calendar year 1999. Through the 1999 ICR, EPA also obtained stack test 
data for certain coal-fired EGUs to verify Hg emissions estimates for 
the EGU source category. 65 FR 79826. EPA further solicited data from 
the public through a February 29, 2000, notice (65 FR 10,783), and 
provided the public an opportunity to provide its views on what the 
regulatory finding should be at a public meeting. 65 FR 79826 (citing 
65 FR 18992). Finally, EPA undertook an evaluation of the Hg control 
performance of various emission control technologies that were either 
currently in use on EGUs or that could be applied to such units for Hg 
control. EPA conducted this evaluation with other parties, including 
the DOE. 65 FR 79826. EPA also evaluated other emission control 
approaches that would reduce EGU HAP emissions. Id. at 79827-29.
    Although Congress did not provide a deadline by which EPA must 
issue the appropriate and necessary finding, the deadlines Congress 
provided for completion of the required studies signal that Congress 
wanted EPA to make the appropriate and necessary finding shortly after 
completion of the studies. Congress required that the Utility Study and 
NIEHS Study be submitted by November 15, 1993, and the Mercury Study by 
November 15, 1994. We reasonably conclude based on the timing of the 
studies that Congress wanted the Agency to evaluate the hazards to 
public health and the environment associated with HAP emissions from 
EGUs as quickly as possible and take steps to regulate such units under 
section 112 if hazards were identified.
    Congress later provided a direct signal as to the timing of the 
appropriate and necessary finding in the committee report associated 
with EPA's fiscal year 1999 appropriations bill, which directed the 
Agency to fund the NAS Study. In that report, Congress indicated that 
it did not want the Agency to make the appropriate and necessary 
finding for Hg until the NAS study was completed. See H.R. Conf. Rep. 
No 105-769, at 281-282 (1998).\20\
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    \20\ This direction is consistent with section 112(n)(1). As 
noted above, the Utility Study was the only condition precedent to 
making the appropriate and necessary finding. The NIEHS study called 
for by 112(n)(1)(C) was to have been completed at the same time as 
the Utility Study. As such, Congress had originally contemplated 
that both the Utility and NIEHS studies would be available at the 
time the Agency made the appropriate and necessary finding. The NAS 
study considered the same information required in the NIEHS study so 
the Congressional direction in the fiscal year 1999 appropriation is 
consistent with the original drafting of section 112(n)(1).
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    After considering all of the information that Congress considered 
most relevant, including the NAS Study that was issued in June 2000, 
EPA determined that it was appropriate and necessary to regulate EGUs 
under section 112 and listed such units for regulation on December 20, 
2000. As explained below, the Agency acted reasonably in issuing the 
finding at that time because of the identified and potential hazards to 
public health and the environment associated with HAP emissions from 
utilities, which the Agency concluded would not be addressed through 
imposition of the requirements of the CAA. It would not have been 
reasonable to delay the finding to collect additional information given 
the considerable delay in completion of the required studies and the 
hazards to public health and the environment identified as of December 
2000.
2. EPA Reasonably Concluded in December 2000 That It Was Appropriate To 
Regulate EGUs Under Section 112
    The December 2000 Finding that it was appropriate to regulate EGUs 
under section 112 focused largely on hazards to public health and the 
environment associated with Hg emissions. EPA reasonably focused on 
this pollutant given that Hg is a persistent, bioaccumulative pollutant 
that causes serious neurotoxic effects. Indeed, Congress specifically 
identified this pollutant as one of concern and required two separate 
studies to be conducted regarding Hg emissions. See Section 
112(n)(1)(B) and (C). The information before the Agency in 2000 
concerning Hg was both well-documented and scientifically supported. 
Based on all of the information before it, the Agency concluded that Hg 
emissions from EGUs posed a hazard to public health. It was also 
reasonable for the Agency to find regulation of EGUs appropriate given 
the uncertainties regarding the extent of public health impacts posed 
by non-Hg HAP. Finally, it was reasonable to base the appropriate 
finding on the availability of controls for HAP emissions from EGUs.
a. The Agency Reasonably Concluded It Was Appropriate To Regulate EGUs 
Based on Hg Emissions
    By 2000, the Agency had amassed ``a truly vast amount of data'' on 
Hg. See October 10, 1997, letter (page 2) submitting Science Advisory 
Board (SAB) peer review recommendations on draft Mercury Study.\21\ 
Those data confirmed the hazards to public health and the environment 
associated with Hg. The data also helped EPA identify the populations 
of most concern with regard to MeHg exposure. See CAA 112(n)(1)(C). 
Finally, the data showed that EGUs were the largest unregulated source 
of Hg emissions in the U.S., and that EGUs were projected to increase 
their Hg emissions to approximately 60 tons in 2010.
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    \21\ http://yosemite.epa.gov/sab/SABPRODUCT.nsf/
FF2962529C7B158A852571AE00648B72/$File/ehc9801.pdf.
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    We discuss below the central pieces of data and information 
concerning Hg that formed the basis of our conclusion that Hg posed a 
threat to public health and the environment.\22\ These conclusions were 
largely drawn from the Mercury Study, which, as noted above, was 
reviewed by over 65 peer reviewers. Upon reviewing the draft report, 
the SAB noted that the ``major findings of the draft report are well 
supported by the scientific evidence.'' In direct response to the SAB 
review, the Agency conducted additional, comprehensive analyses 
addressing SAB's recommendations. Thus, in 2000, the Agency had before 
it a comprehensive record concerning Hg emissions, including the best 
available science on Hg at the time.
---------------------------------------------------------------------------

    \22\ The central conclusions underlying the 2000 finding are 
described in detail in the 2000 notice, at 65 FR 79829-30.
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i. Key Facts: Impacts of Hg on Health and the Environment
    EPA first concluded that Hg from EGUs was the HAP of greatest 
concern. Id. at 79827. The Agency explained that ``mercury is highly 
toxic, persistent, and bioaccumulates in food chains;'' that Hg 
deposited on land and water can then be metabolized by microorganisms 
into MeHg; that MeHg is ``a highly toxic, more bioavailable, form that 
biomagnifies in the aquatic food chain (e.g., fish);'' and that nearly 
all of the Hg in fish is MeHg. 65 FR 79827. The Agency further noted 
that fish consumption is the primary route of exposure for humans and 
wildlife, and, by July 2000, 40 states and America Samoa had issued 
fish advisories for Hg,

[[Page 24995]]

with 13 of those states issuing advisories for all the water bodies in 
their state. 65 FR 79827. Finally, the Agency explained that 
neurotoxicity is the health effect of greatest concern with MeHg 
exposure, and that exposures to MeHg can have serious toxicological 
effects on wildlife as well as humans.
    EPA recognized that increased Hg deposition would lead to increased 
levels of MeHg in fish and such ``increased levels in fish [would] * * 
* lead to toxicity in fish-eating birds and mammals, including 
humans.'' 65 FR 79830. EPA agreed with the NAS that ``the long term 
goal needs to be the reduction in the concentrations of methylmercury 
in fish'' and concluded that reducing Hg emissions from EGUs was ``an 
important step toward achieving that goal.'' 65 FR 79830.
    The Agency then identified the most affected populations. 
Specifically, the Agency concluded that women of childbearing age are 
the population of greatest concern because the developing fetus is the 
most sensitive to the effects of MeHg. 65 FR 79827. EPA estimated that 
at that time, 7 percent of women of childbearing age (or about 
4,000,000 women) in the continental U.S. were exposed to MeHg at levels 
that exceeded the RfD and that about 1 percent of women of childbearing 
age (or about 580,000 women) had MeHg exposures 3 to 4 times the RfD. 
65 FR 79827.
    The NAS Study affirmed EPA's assessment of the toxicity of MeHg and 
that the RfD EPA had developed for MeHg was valid. 65 FR 79827. The 
Agency acknowledged that there was uncertainty with risk at exposure 
above the RfD, but indicated that risk increased with increased 
exposure. 65 FR 79827. In addition to focusing on women of childbearing 
age and developing fetuses, EPA stated a particular concern for 
subsistence fish-eating populations due to their regular and frequent 
consumption of relatively large quantities of fish. 65 FR 79830.
    As for environmental effects, the Agency observed adverse effects 
to avian species and wildlife in laboratory studies at levels 
corresponding to fish tissue MeHg concentrations that are exceeded by a 
significant percentage of fish sampled in lake surveys. 65 FR 79830. 
The Agency explained that wildlife consume fish from a more localized 
geographic area than humans, which can result in elevated levels of Hg 
in certain fish eating species. Those species include, for example, the 
kingfisher and some endangered species, such as the Florida panther. 65 
FR 79830.
    In summary, in the December 2000 Finding, EPA identified Hg in the 
environment as a hazard to public health and the environment, 
determined that a significant segment of the most sensitive members of 
the population were exposed to MeHg at levels exceeding the RfD, and 
confirmed that the RfD was valid.
ii. EGU Emissions of Hg
    In the 2000 finding, the Agency estimated that about 60 percent of 
the total Hg deposited in the U.S. came from U.S. anthropogenic air 
emission sources. 65 FR 79827. The Agency stated that the remainder of 
the Hg deposited in the U.S. was from natural emission sources, 
reemissions of historic global anthropogenic Hg releases, and non-
domestic anthropogenic sources of Hg. 65 FR 79827. EPA identified coal 
combustion and waste incineration as the source categories likely to 
bear the greatest responsibility for direct anthropogenic Hg deposition 
in the continental U.S. 65 FR 79827. EPA further explained that EGUs 
are the largest unregulated domestic source of Hg emissions, accounting 
for approximately 30 percent of the current anthropogenic air emissions 
from domestic sources. 65 FR 79827. These numbers, taken together, 
reveal that EGUs accounted for approximately 18 percent of the total Hg 
deposition in the U.S on an annual basis, considering all U.S. 
anthropogenic sources, natural emission sources, reemissions of 
historic global anthropogenic Hg releases, and non-domestic 
anthropogenic sources of Hg.\23\
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    \23\ EPA estimated that U.S. anthropogenic air emissions of 
mercury accounted for 60 percent of total deposition in the U.S. and 
U.S. EGUs accounted for 30 percent of that deposited mercury. Thirty 
percent of the 60 percent contribution is equal to approximately 18 
percent of the total deposition. See Utility Study, page 7-28.
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    In 2000, the Agency also found a plausible link between domestic 
anthropogenic Hg emissions and MeHg in fish. 65 FR 79829. The Agency 
explained that although that link could not be estimated quantitatively 
at the time, the facts before the Agency were sufficient for it to 
conclude that EGU Hg emissions posed a hazard to public health. Id. at 
79830. Those facts included, for example, the link between coal 
consumption and Hg emissions, EGUs being the largest domestic source of 
Hg, and certain segments of the population being at risk for adverse 
health effects due to consumption of contaminated fish. Id.
iii. EPA's Conclusions Regarding Hg
    Based on the foregoing and all of the information set forth in the 
December 20, 2000, notice, the Agency found that Hg emissions from EGUs 
posed a hazard to public health and the environment. In making this 
finding, the Agency focused on the significant adverse health effects 
associated with MeHg and the persons most adversely impacted by Hg. The 
populations most affected were women of childbearing years and their 
developing fetuses and subsistence fishers. The Agency viewed the 
adverse health effects and environmental effects described above in 
conjunction with the then current Hg emissions information provided by 
EGUs in response to the 1999 ICR. Based on that information, EPA 
concluded that EGUs accounted for approximately 30 percent of the U.S. 
anthropogenic emissions of Hg, which translated into about 18 percent 
of the total Hg deposition in the U.S. at that time. EPA also knew that 
Hg from EGUs comprised an undetermined amount of the reemissions of Hg. 
See Mercury Study, Volume 3, page 2-3.
    At the time of the December 2000 Finding, the Agency had issued 
section 112 or 129 standards for several of the other source categories 
that were significant Hg emitters, and the Agency was required by the 
CAA to establish section 112 or 129 standards for the other significant 
Hg emitters. See Standards for Large Municipal Waste Combustors, 40 CFR 
part 60, subpart Ea (NSPS), 56 FR 5507 (February 11, 1991), as amended, 
and 40 CFR part 60, subpart Eb (Emissions Guidelines), 60 FR 65419 
(December 19, 1995), as amended; Standards for Medical Waste 
Incinerators, 40 CFR part 60, subpart Ec (NSPS), 62 FR 48382 (September 
15, 1997), as amended, and 40 CFR part 60, subpart Ce (Emission 
Guidelines), 62 FR 48379 (September 15, 1997); Standards for Hazardous 
Waste Combustors, 40 CFR part 63, subpart EEE, 64 FR 53038 (September 
30, 1999); Standards for Small Municipal Waste Combustors, 40 CFR part 
60, subpart AAAA (NSPS), 65 FR 76355 (December 6, 2000), and 40 CFR 
part 60, subpart BBBB (Emissions Guidelines), 65 FR 76384 (December 6, 
2000); and standard for Portland cement manufacturers (40 CFR part 63, 
subpart LLL, 64 FR 31925 (June 14, 1999)).\24\ Most of these categories 
emitted far less Hg than EGUs at the time of the finding. Thus, at the 
time EPA made the December 2000 Finding, the record

[[Page 24996]]

reflected that Hg posed hazards to public health and the environment, 
that EGUs were the single largest unregulated domestic source of Hg 
emissions, and that HAP emissions from EGUs would remain unregulated 
absent listing under section 112. EPA reasonably found at the time that 
reducing Hg emissions from EGUs would further the goal of mitigating 
the hazards to public health and the environment posed by Hg.
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    \24\ The NESHAP for Portland cement did not include a standard 
for Hg when initially promulgated. In National Lime Ass'n v. EPA, 
the DC Circuit Court held that section 112(d) contains a clear 
statutory directive to regulate all HAP emitted from a listed source 
category. 233 F.3d 624, 634 (DC Cir. 2000). EPA recently issued 
final section 112 standards for Portland cement manufacturers, 
including a standard for Hg emissions from such sources.
---------------------------------------------------------------------------

    EPA also reasonably predicted that incremental reductions in Hg 
emissions, including from EGUs, would lead to incremental reductions in 
the MeHg concentration in fish tissue, and that such reductions would, 
in turn, reduce the risk to public health and the environment. 65 FR 
79830. The Mercury Study recognized that Hg is a metal that remains in 
the environment permanently and can circulate continuously through 
various environmental media. Although EPA was aware that reductions of 
Hg from anthropogenic sources may not lead to immediate reductions in 
fish tissue levels, such reductions would nonetheless serve the long-
term goal of reducing the mobilization of Hg to the atmosphere and thus 
reduce MeHg concentrations in fish.
    EPA, therefore, reasonably determined based on the facts that 
existed at the time that regulation of EGUs was appropriate in order to 
reduce the hazards to public health and the environment associated with 
the Hg emissions from EGUs. EPA expressly acknowledged that there were 
uncertainties concerning the extent of the risk due to Hg emissions 
from EGUs, because the Agency had not quantified the amount of MeHg in 
fish that was directly attributable to EGUs compared to other sources 
of MeHg. 65 FR 79827. That EPA did not quantify in 2000 the amount of 
MeHg in fish due to EGUs did not preclude EPA from making an 
``appropriate'' finding. Nowhere in section 112(n)(1) or in its 
direction concerning the NAS Study did Congress require EPA to quantify 
the amount of MeHg in fish tissue that was directly attributable to 
EGUs.\25\ Moreover, EPA did not have sufficient confidence in its 
modeling tools at the time to draw conclusions about the contribution 
of specific source types to fish MeHg concentrations in specific 
geographic areas or nationally. These uncertainties are well described 
in the Utility, Mercury, and NAS Studies.
---------------------------------------------------------------------------

    \25\ Consistent with section 112(n)(1), none of the studies 
addressed the amount of MeHg in fish attributable solely to EGUs. 
Instead, in the Utility and Mercury Studies, EPA discussed the 
significant contribution EGUs made to Hg deposition and that Hg 
deposition was problematic from a health and environmental 
standpoint. EPA submitted both the Utility Study and the Mercury 
Study to Congress by 1998. Aware of these studies, Congress, when 
directing the additional NAS Study, still did not require EPA to 
determine the amount of MeHg in fish due solely to EGUs. In light of 
this fact and the broad discretion Congress gave EPA to determine 
whether it was appropriate or necessary to regulate EGUs under 
section 112, EPA acted reasonably in 2000 by not delaying its 
finding several years to conduct an analysis of the portion of MeHg 
in fish due solely to EGUs.
---------------------------------------------------------------------------

    In any event, in light of the breadth of the scientific evidence 
before the Agency and the conclusions the Agency reached, it would not 
have been reasonable to delay the finding to develop an analytical tool 
to apportion the Hg in fish. The Hg problem at the time was well 
documented, and the fact that EGUs represented such a significant 
portion of the Hg deposition in the U.S. was ample evidence that it was 
appropriate to regulate emissions from EGUs--the single largest 
unregulated domestic source of Hg emissions. 65 FR 79827.
    Finally, the Agency had already delayed in completing the section 
112(n)(1) studies. Additional delay would have been unreasonable 
because of the persistence of Hg in the environment and its tendency to 
bioaccumulate up the food chain, both aspects of Hg in the environment 
that make it critical to limit additional releases to the environment 
as quickly as possible. In addition, delay would have been unreasonable 
because EPA estimated at that time that about 7 percent of women of 
child-bearing age, one of the most at-risk populations, was exposed to 
Hg at levels exceeding the RfD, and EPA knew that as the level of 
exposure above the RfD increased, the level of risk and the extent and 
severity of adverse effects increased. Thus, EPA reasonably made the 
appropriate and necessary determination in 2000 to ensure that the 
largest unregulated domestic source of Hg would be required to install 
controls, thereby achieving an incremental reduction in the risk 
associated with a persistent, bioaccumulative HAP.
b. The Appropriate Finding for Non-Hg HAP Was Reasonable
    The December 2000 Finding was also reasonable as it pertained to 
the non-Hg HAP emitted from EGUs. The Agency found it was appropriate 
to regulate EGUs based on the potential human health concerns from non-
Hg HAP, particularly Ni from oil-fired EGUs, and the uncertainties 
regarding the public health impact of emissions of such HAP. 65 FR 
79830. Based on the information in the Utility Study, EPA could not 
conclude based on the available information that the non-Hg HAP posed 
no hazards to public health.
    Specifically, the Agency noted that several non-Hg HAP metals, 
including As, Cr, Ni, and Cd, were of potential concern for 
carcinogenic effects. 65 FR 79827. EPA acknowledged that the risks did 
not appear high, but it stated that the risks were not sufficiently low 
to disregard the metals as a potential concern for public health. 65 FR 
79827; see Utility Study, Table 5-4, page 5-9 (finding cancer risks 
from oil-fired EGUs alone for Ni exceeded 1 in a million). The Agency 
also indicated that dioxins, HCl, and HF were of potential concern and 
might be evaluated further. 65 FR 79827.
    EPA did not view the risks associated with non-Hg HAP in a vacuum. 
Rather, EPA considered the threat to public health, including 
uncertainties, associated with both Hg and non-Hg HAP emissions from 
EGUs in determining whether it was appropriate to regulate such units 
under section 112.
    Finally, even looking solely at non-Hg HAP, EPA's conclusions 
support regulation of EGUs under section 112. Although Congress 
provided no metric for the hazard to public health determination, 
section 112(c)(9) is instructive. Specifically, in that section, 
Congress set forth a test for removing source categories from the 
section 112(c) source category list. That test is relevant because it 
reflects Congress' view as to the level of health effects associated 
with HAP emissions that Congress thought warranted regulation under 
section 112. If a source category failed to meet that test, it would 
remain subject to the requirements of CAA section 112. Thus, CAA 
section 112(c)(9) can be read to reflect Congress' view of what adverse 
public health effects from HAP emissions are acceptable and thus do not 
warrant regulation under CAA section 112.
    For carcinogens, which are at issue here, section 112(c)(9)(B)(i) 
provides that EPA may delete a source category from the section 112(c) 
list if no source in the category (or group of sources in the case of 
area sources) emits such HAP in quantities that 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). Thus, section 
112(c)(9)(B)(i) prohibits the Agency from delisting a major source 
category from the section 112(c) list if any single source within that 
category emits cancer causing HAP at levels that may cause a

[[Page 24997]]

lifetime cancer risk greater than one in one million to the most 
exposed individual. The Utility Study demonstrated that there were EGUs 
whose emissions resulted in a cancer risk greater than one in one 
million. Accordingly, it was reasonable to conclude at the time that 
non-Hg HAP emissions were of sufficient concern from a health 
perspective to warrant regulation.
3. EPA Reasonably Based the Appropriate Determination in Part on the 
Availability of Controls for HAP Emissions From EGUs
    In addition to determining that it was appropriate to regulate 
because of the known and potential hazards to public health and the 
environment, EPA also concluded that it was appropriate to regulate HAP 
emissions from EGUs because EPA had identified a number of control 
options that would effectively reduce HAP emissions from EGUs. 65 FR 
79828-30. EPA discussed the various controls available to reduce HAP 
emissions from EGUs in the December 2000 Finding. The approach of 
section 112, as amended in 1990, is based on the premise that, to the 
extent there are controls available to reduce HAP emissions, sources 
should be required to use them. Thus, it was reasonable to base the 
appropriate finding in part on the conclusion that controls currently 
available were expected to reduce HAP emissions from EGUs.
4. EPA Reasonably Concluded It Was Necessary To Regulate EGUs
    In 2000, EPA found it was necessary to regulate HAP emissions from 
EGUs under section 112 because the imposition of the other requirements 
of the CAA would not address the serious public health and 
environmental hazards arising from such emissions. 65 FR 79830. EPA 
also noted that Congress enacted section 112 specifically to address 
HAP emissions from stationary sources, and it was thus reasonable to 
regulate HAP emissions from EGUs under that section given the hazards 
to public health and the environment posed by such emissions. Id.
    In Table 1 of the December 20, 2000 notice, EPA set forth its 
projections of HAP emissions for 2010. In assessing those projections 
in 2000, EPA considered the data that it had obtained as the result of 
the 1999 ICR. 65 FR 79828. It also considered projected changes in the 
population of units, fuel consumption, and control device 
configuration. Id. EPA considered control device configurations in 
making the 2010 projections, in an effort to account for the reductions 
attributable to the imposition of other requirements of the CAA.
    Specifically, in estimating the projected 2010 HAP emissions from 
EGUs, EPA accounted for the HAP reductions that would occur as the 
result of the controls required to comply with the ARP. Congress added 
the ARP in CAA Title IV, as part of the 1990 amendments, and that 
program is primarily directed at EGUs. EPA, therefore, considered the 
HAP reductions projected to occur as the result of control 
configurations needed to meet the Acid Rain requirements of the CAA. 
See, e.g., Utility Study, ES-2.
    As shown in Table 1 of the December 20, 2000 notice, EPA estimated 
that the level of all HAP emitted by coal-fired EGUs would increase by 
2010. 65 FR 79828 (Table 1). For Hg, EPA estimated that EGUs emitted 46 
tons of Hg in 1990 and 43 tons of Hg in 1999, and it projected that 
EGUs would emit approximately 60 tons of Hg in 2010. 65 FR 79827-828. 
EPA also estimated an overall increase in non-Hg HAP emissions from 
coal-fired EGUs. Given these estimates and projections, which were 
based on the best information available at the time, EPA reasonably 
concluded that the identified and potential hazards associated with HAP 
from coal-fired EGUs would not be addressed through imposition of the 
other requirements of the CAA.
    For oil-fired EGUs, EPA projected a decline in overall HAP 
emissions. The decline was primarily due to projected retirements and 
fuel switching from oil to natural gas. EPA could not conclude based on 
the information available at the time that the facilities posing the 
cancer risks, due primarily to Ni emissions, would retire or change 
fuels. As a result of these uncertainties and the uncertainties as to 
the extent of the public health impact from oil-fired units, EPA found 
that it was necessary to regulate such units under section 112.
5. The 2005 Action: EPA Erred in the 2005 Action by Concluding That the 
December 2000 Finding Lacked Foundation
    In 2005, the Agency asserted that the December 2000 Finding lacked 
foundation for two reasons. First, the Agency stated that the 2000 
appropriate finding was overbroad to the extent it relied on adverse 
environmental effects. Second, the Agency stated that the 2000 
appropriate finding lacked foundation because EPA did not fully 
consider the Hg emissions remaining after imposition of the 
requirements of the CAA. For the reasons provided below, we reject 
these assertions as unfounded. As demonstrated above, EPA's 2000 
appropriate and necessary finding was sound and fully supported by the 
record before the Agency in 2000.
a. Consideration of Environmental Effects in the Appropriate Finding
    EPA reasonably examined the adverse environmental impacts 
associated with Hg in making the December 2000 Finding. In 2005, EPA 
changed its interpretation of the broad term ``appropriate'' to 
restrict the consideration of environmental effects only to situations 
where the Agency had determined that a hazard to public health exists 
as a result of EGU HAP emissions. As such, EPA stated in 2005 that the 
December 2000 Finding lacked foundation to the extent it was based on 
environmental effects.
    As explained above in Section III.A, EPA's 2005 change in how it 
interpreted the term ``appropriate'' lacks merit. Congress gave EPA 
broad discretion to determine whether it was appropriate to regulate 
EGUs under section 112. On the one hand, EPA recognized that broad 
discretion in 2005, but on the other hand, it sought to limit that 
discretion by only allowing environmental impacts to be considered if a 
hazard to public health was found. The 2005 interpretation was based on 
the flawed notion that the Agency should only consider health effects 
because the Utility Study only required consideration of hazards to 
public health. But, as noted above, Congress specifically directed EPA 
in section 112(n)(1)(B) to consider the environmental effects 
associated with Hg emissions from EGUs. It was entirely reasonable, 
therefore, for EPA to consider such effects in making its appropriate 
finding in 2000.
    Furthermore, even under the Agency's flawed 2005 interpretation, 
which allowed consideration of environmental effects only where a 
hazard to public health exists, EPA properly considered environmental 
effects in 2000 because we, in fact, found a hazard to public health 
based on the record at that time.
b. Scope of ``Appropriate'' Finding
    EPA interprets the ``appropriate'' finding to require an evaluation 
of the hazards to public health and the environment at the time of the 
finding. This interpretation is consistent with the approach taken in 
2000. By contrast, in the 2005 ``appropriate'' analysis, EPA considered 
the hazards to public health that were reasonably anticipated to occur 
``after imposition of the requirements of the Act.'' In short, EPA 
infused the ``after imposition of the requirements of the Act'' inquiry 
into

[[Page 24998]]

both the appropriate and necessary prongs.
    As explained in Section III.A, this interpretation improperly 
conflates the ``appropriate'' and ``necessary'' analysis. Accordingly, 
any assertion that EPA's 2000 appropriate finding is flawed because the 
Agency failed to consider the other requirements of the CAA should be 
rejected.
    Even considering the Agency's flawed 2005 interpretation of the 
term ``appropriate,'' there is nothing in the record to suggest that 
the Agency erred in 2000 with regard to assessing Hg emissions. As 
explained above, in 2000, EPA reasonably considered those requirements 
of the CAA that directly pertained to EGUs (i.e., the ARP in Title IV 
of the Act).
    In addition, in 2000, EPA recognized that EGUs may be subject to 
requirements pursuant to SIP developed in response to NAAQS. In fact, 
EPA had projected a potential 11 tpy reduction in EGU Hg emissions as 
the result of the ozone and PM NAAQS. Utility Study, p. 1-3. EPA 
explained in the Utility Study, however, why it did not account for 
such reductions in its 2010 emission projections.
    First, EPA explained that some of the Hg reductions associated with 
the PM and ozone NAAQS would be realized through the implementation of 
the ARP, and, thus, had already been accounted for in its 2010 
projections. See Utility Study, page 1-3. Thus, to consider the 
projected reductions from the NAAQS would have potentially led to 
double counting of the estimated HAP reductions. Second, the states, 
not EPA, are primarily responsible for implementation of the NAAQS. EPA 
could not have reasonably assumed that the estimated Hg reductions from 
EGUs would occur because it could not forecast the prospective 
regulatory actions of the states and the impact that those actions 
would have on HAP emissions. In short, there was no guarantee that 
states would regulate EGUs to achieve the reductions necessary to meet 
the NAAQS in such a way that would achieve Hg reductions, and EPA 
reasonably did not consider such possible reductions in its 2000 
analysis.
    Furthermore, at the time of the Utility Study, no areas had been 
designated as nonattainment with the 1997 revised PM NAAQS. See Utility 
Study, page 2-32. Even had all areas been designated at the time of the 
Utility Study, we still would not have known how the states would have 
elected to obtain the required reductions to meet the NAAQS. We also 
would not have had information as to how the sources would actually 
implement the requirements in any SIP, and as noted above, the degree 
of HAP co-benefit reductions varies depending on the control approach 
used. Even had we considered the potential 11 tpy of Hg reductions 
estimated to occur as a result of implementing the 1997 NAAQS, the 
projected level of Hg emissions from EGUs in 2010 would have been 49 
tpy (60 - 11 = 49), which is still 6 tpy greater than the 43 tpy that 
the Agency concluded in 2000 caused a hazard to public health and the 
environment. Thus, even if the NAAQS had been included in the 2010 
projections, the Agency would still have found that the identified 
hazards would not be resolved through imposition of the requirements of 
the CAA and would have concluded it was necessary to regulate EGUs 
under section 112.
    EPA also asserted in 2005 that it failed to account for Hg 
reductions associated with the 1997 Utility NSPS in assessing whether 
it was appropriate to regulate in 2000. In the Utility Study, EPA noted 
that EGUs would be implementing the same controls for NOX 
and SO2 to meet the requirements of both Title I and Title 
IV. EPA accounted for the ARP in its 2010 projections. In addition, in 
the Utility Study, EPA determined that HAP emissions from EGUs would 
increase in 2010 based on estimated increases in coal use, which was 
primarily projected to occur at new units. Utility Study, pages 2-26 to 
2-31. Because EPA was unable to determine the size and location of the 
new units at the time of the Utility Study, the Agency reasonably 
allocated the increased fuel consumption to existing units (excluding 
the coal-fired units that were projected to retire between 1990 and 
2010). All or a substantial majority of existing units already had some 
type of PM control and many units had scrubbers. To the extent this 
approach of assigning increased fuel consumption to existing controlled 
units led to an overestimation of remaining HAP emissions, we do not 
believe the overestimation was significant. EPA's approach to 
projecting emissions in 2010 was entirely reasonable given the data and 
information available to the Agency at the time. See Utility Study, 
page 6-15.
    Finally, EPA asserted in 2005 that it failed to account for the Hg 
reductions associated with the NOX SIP call. Like the NAAQS, 
states are primarily responsible for developing regulations to meet the 
NOX SIP call. EPA could not have reasonably assumed that the 
estimated Hg reductions from EGUs would occur because it could not 
forecast the prospective regulatory actions of the states. In addition, 
in 2005, EPA neither identified the reductions that would occur as the 
result of the NOX SIP call, nor explained how those 
reductions would have changed EPA's 2000 appropriate finding.
    EPA solicits comment on section III.B.

C. EPA Must Regulate EGUs Under Section 112 Because EGUs Were Properly 
Listed Under CAA Section 112(c)(1) and may not be Delisted Because They 
do not Meet the Delisting Criteria in CAA Section 112(c)(9)

    As shown above, in 2000, EPA reasonably determined, based on the 
record before it at the time, that it was appropriate and necessary to 
regulate EGUs under CAA section 112. Once that finding was made, EPA 
properly listed EGUs pursuant to section 112(c), and EGUs remain a 
listed source category. See New Jersey, 517 F.3d at 583.
    As the DC Circuit Court held in New Jersey, EPA cannot ignore the 
delisting criteria in section 112(c)(9). CAA section 112(c)(9)(B) 
authorizes the Agency to delist any source category if the Agency 
determines that: (1) For HAP that may cause cancer in humans, no source 
in the category emits such HAP in quantities that ``may cause a 
lifetime risk of cancer greater than one in one million'' to the most 
exposed individual; section 112(c)(9)(B)(i); and (2) for HAP that may 
result human health effects other than cancer or adverse environmental 
effects, ``emissions from no source in the category or subcategory 
concerned * * * exceeds 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.'' Section 
112(c)(9)(B)(ii).
    Here, we have a validly listed source category. EPA could not have 
met the delisting criteria in 2000 or 2005, and it still cannot meet 
those criteria today.
    The information in the Utility Study shows that HAP emissions from 
a number of EGUs caused a lifetime cancer risk greater than one in one 
million. Nothing in the 2005 record suggested anything to the contrary, 
and as such, the Agency did not delist EGUs in 2005 pursuant to section 
112(c)(9). Finally, EPA has conducted 16 case studies based on the data 
collected in support of this proposed rule and determined that 4 of 
those facilities evaluated (25 percent) presented a lifetime cancer 
risk greater than 1 in 1 million. Thus, based on current data and 
analysis, EGUs fail the first requirement for delisting set forth in 
section 112(c)(9)(B)(i). Because EGUs do

[[Page 24999]]

not meet the first delisting requirement, the Agency need not determine 
whether the second delisting requirement is satisfied; however, the 
Agency believes that EGUs would similarly fail the second delisting 
requirement for the reasons described below in section III.D.

D. New Analyses Confirm That it Remains Appropriate and Necessary to 
Regulate U.S. EGU HAP Under Section 112

    As explained above, the December 2000 appropriate and necessary 
determination is wholly supported by the record that was before the 
Agency at the time it made its decision. Although not required, we 
conducted additional technical analyses because several years have 
passed since the December 2000 Finding. These extensive analyses 
confirm that it remains appropriate and necessary today to regulate 
EGUs under section 112. We discuss below the new analyses that we 
conducted. We also explain why these analyses and the other information 
currently before the Agency confirm that regulation of EGUs under 
section 112 is appropriate and necessary. We solicit comment on the new 
analyses.
    Utilities are by far the largest remaining source of Hg in the 
U.S.\26\ In addition, EGUs are the largest source of HCl, HF, and Se 
emissions, and a major source of metallic HAP emissions including As, 
Cr, Ni, and others.\27\ The discrepancy is even greater now that almost 
all other major source categories have been required to control Hg and 
other HAP under section 112.
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    \26\ Strum, M., Houyoux, M., U.S. Environmental Protection 
Agency. Emissions Overview: Hazardous Air Pollutants in Support of 
the Proposed Toxics Rule. Memorandum to Docket EPA-HQ-OAR-2009-0234. 
March 15, 2011.
    \27\ Ibid. Tables 3 and 4.
---------------------------------------------------------------------------

    These significant HAP emissions pose a known or potential hazard to 
public health and the environment and, thus, it remains appropriate to 
regulate EGUs under section 112.
    In this section, we describe briefly the health and environmental 
effects associated with the HAP emitted by EGUs and summarize the new 
analyses that the Agency conducted to assess the hazards to public 
health and the environment associated with EGU emissions, including the 
hazards remaining after imposition of the requirements of the CAA. We 
then discuss our conclusion that it remains appropriate and necessary 
to regulate EGUs under section 112.
    Specifically, we conclude today that it remains appropriate to 
regulate EGUs under section 112 because Hg is a persistent, 
bioaccumulative pollutant, and emissions of Hg from EGUs continue to 
pose a hazard to public health and to the environment. Because of the 
persistent nature of Hg in the environment, Hg emitted today can lead 
to re-emissions of Hg in the future, and as a result continue to 
contribute to Hg deposition and associated health and environmental 
hazards in the future.
    In addition, we conclude today that it is appropriate to regulate 
non-Hg HAP because emissions of these HAP from some EGUs pose a cancer 
risk greater than one in one million to the most exposed 
individual.\28\ EGUs remain the largest contributors of several HAP 
(e.g., HF, Se, HCl), and are among the largest contributor for other 
HAP (e.g., As, Cr, Ni, hydrogen cyanide (HCN)).\29\ EPA recognizes that 
there are additional health and environmental effects for which we have 
insufficient information to quantify risks, or which have a higher 
degree of uncertainty regarding the weight of evidence for causality. 
While not quantified in our analysis, the potential for additional 
hazards to public health and the environment beyond what we have 
analyzed provides additional support for regulation under section 112 
that will assure reductions of all HAP and the risks, quantified or 
unquantified, that they pose.
---------------------------------------------------------------------------

    \28\ Strum, M., Thurman, J., and Morris, M., U.S. Environmental 
Protection Agency. Non-Hg Case Study Chronic Inhalation Risk 
Assessment for the Utility MACT ``Appropriate and Necessary'' 
Analysis. Memorandum to Docket EPA-HQ-OAR-2009-0234. March 1, 2011.
    \29\ Strum, M., Houyoux, H., op. cit., Tables 3 and 4.
---------------------------------------------------------------------------

    Finally, we find that it remains appropriate to regulate EGUs under 
section 112 because we have identified a number of currently available 
control technologies that will adequately address HAP emissions from 
EGUs. Several of these findings provide an independent basis for our 
determination consistent with our interpretation of the appropriate 
finding set forth above, and the combined weight of these findings 
provides a strong overall basis for our determination that it is and 
remains appropriate to regulate EGUs under CAA section 112.
    We conclude that it remains necessary to regulate HAP emissions 
from EGUs because the imposition of the requirements of the CAA will 
not sufficiently address the hazards to public health and the 
environment posed by Hg emissions or the cancer risk and potential 
hazards to the environment posed by non-Hg HAP emissions from EGUs. 
Although the identified hazards will not be fully addressed through 
regulation under section 112, there will be a significant reduction in 
domestic Hg and non-Hg HAP emissions as the result of a section 112 
regulation. EGUs remain the largest source of HCl and HF emissions in 
the U.S., and it is essential that those emissions be reduced to the 
maximum extent achievable, as Congress envisioned pursuant to section 
112. Furthermore, it is necessary to regulate EGUs under section 112 
because standards under that section assure that reductions in HAP 
emissions from EGUs will be permanently realized, thereby assuring that 
recent decreases in HAP emissions from U.S. EGUs will not be reversed 
in the future. Each of these conclusions independently supports our 
determination that it remains necessary to regulate EGUs under section 
112.
    Below we present an overview of EPA's current view of the 
scientific and technical information relevant to evaluating U.S. EGU Hg 
emissions and the public health hazards associated with such emissions. 
We provide general background information on the health hazards and 
environmental impacts of Hg and its transformation product MeHg; the 
emissions of those pollutants; the U.S. EGU contribution to these 
emissions; the predominant exposure pathway by which humans are 
affected by MeHg, which is by ingestion of fish containing MeHg; EPA's 
methodology for determining the impacts of U.S. EGU Hg emissions on 
potential exposures to MeHg in fish; the estimated potential risks 
associated with recent and future anticipated emissions of Hg from U.S. 
EGUs; and a qualitative analysis of the environmental hazards 
associated with Hg deposition. In addition to these analyses of hazards 
to public health and the environment associated with emissions of Hg 
from U.S. EGUs, this section also includes analyses of the hazards to 
public health and the environment from U.S. EGU emissions of non-Hg 
HAP. We then explain why the hazards to public health and the 
environment from Hg and non-Hg HAP emissions are reasonably anticipated 
to remain from U.S. EGUs after imposition of the requirements of the 
CAA. Finally, we discuss our evaluation of the new data and our finding 
that it remains appropriate and necessary to regulate EGUs under 
section 112.
1. Background Information on Hg Emissions, Deposition, and Effects on 
Human Health and the Environment
a. Overview of Hg and Associated Health and Environmental Hazards
    Mercury is a persistent, bioaccumulative toxic metal that is 
emitted from EGUs in three forms:

[[Page 25000]]

Gaseous elemental Hg (Hg\0\), oxidized Hg compounds (Hg\+2\), and 
particle-bound Hg (HgP). Elemental Hg does not quickly 
deposit or chemically react in the atmosphere, resulting in residence 
times that are long enough to contribute to global scale deposition. 
Oxidized Hg and HgP deposit quickly from the atmosphere 
impacting local and regional areas in proximity to sources. 
Methylmercury is formed by microbial action in the top layers of 
sediment and soils, after Hg has precipitated from the air and 
deposited into waterbodies or land. Once formed, MeHg is taken up by 
aquatic organisms and bioaccumulates up the aquatic food web. Larger 
predatory fish may have MeHg concentrations many times, typically on 
the order of one million times, that of the concentrations in the 
freshwater body in which they live. Although Hg is toxic to humans when 
it is inhaled or ingested, we focus in this rulemaking on exposure to 
MeHg through ingestion of fish, as it is the primary route for human 
exposures in the U.S., and potential health risks do not likely result 
from Hg inhalation exposures associated with Hg emissions from 
utilities.
    In 2000, the National Research Council (NRC) of the NAS issued the 
NAS Study, which provides a thorough review of the effects of MeHg on 
human health. There are numerous studies that have been published more 
recently that report effects on neurologic and other endpoints.
i. Reference and Benchmark Doses
    As discussed earlier in Sections II.A.1 and III.B.3.a.i of this 
preamble, EPA has set and evaluated the RfD for Hg several times, and 
has received input from the NRC on the appropriateness of the RfD. In 
1995, EPA set a health-based ingestion rate for chronic oral exposure 
to MeHg termed an oral RfD, at 0.0001 milligrams per kilogram per day 
(mg/kg-day).\30\ The RfD was based on effects reported for children 
exposed in utero during the Iraqi Hg poisoning episode, in which 
children were exposed to high levels of Hg when their mothers consumed 
contaminated grain.\31\ Subsequent research from large epidemiological 
studies in the Seychelles,\32\ Faroe Islands,\33\ and New Zealand \34\ 
added substantially to the body of knowledge on neurological effects 
from MeHg exposure. In 2001 EPA established a revised RfD based on the 
advice of the NAS and an independent review panel convened as part of 
the Integrated Risk Information System (IRIS) process. In their 
analysis, the NAS examined in detail the epidemiological data from the 
Seychelles, the Faroe Islands, and New Zealand, as well as other 
toxicological data on MeHg. The NAS recommended that neurobehavioral 
deficits as measured in several different tests among these studies be 
used as the basis for the RfD.
---------------------------------------------------------------------------

    \30\ MeHg exposure is measured as milligrams of MeHg per 
kilogram of bodyweight per day, thus normalizing for the size of 
fish meals and the differences in bodyweight among exposed 
individuals.
    \31\ Marsh DO, Clarkson TW, Cox C, Myers GJ, Amin-Zaki L, Al-
Tikriti S 1987. Fetal methylmercury poisoning. Relationship between 
concentration in single strands of maternal hair and child effects. 
Arch Neurol 44(10):1017-1022.
    \32\ Davidson, P.W., G. Myers, C.C. Cox, C.F. Shamlaye, 
D.O.Marsh, M.A.Tanner, M. Berlin, J. Sloane-Reeves, E. 
Chernichiari,, O. Choisy, A. Choi and T.W. Clarkson. 1995. 
Longitudinal neurodevelopment study of Seychellois children 
following in utero exposure to methylemrcury from maternal fish 
ingestion: outcomes at 19 and 29 months. NeuroToxicology 16:677-688.
    \33\ Grandjean, P., Weihe, P., White, R.F., Debes, F., Araki, 
S., Murata, K., S[oslash]rensen, N., Dahl, D., Yokoyama, K., 
J[oslash]rgensen, P.J., 1997. Cognitive deficit in 7-year-old 
children with prenatal exposure to methylmercury. Neurotoxicol. 
Teratol. 19, 417-428.
    \34\ Kjellstrom T, Kennedy P, Wallis S, Stewart A, Friberg L, 
Lind B, et al. (1989). Physical and mental development of children 
with prenatal exposure to mercury from fish. Stage 2: Interviews and 
psychological tests at age 6. Solna, Sweden: National Swedish 
Environmental Protection Board. Report No.: Report 3642.
---------------------------------------------------------------------------

    The NAS proposed that the Faroe Islands cohort was the most 
appropriate study for defining an RfD, and specifically selected 
children's performance on the Boston Naming Test (a neurobehavioral 
test) as the key endpoint. Results from all three studies were 
considered in defining the RfD, as published in the ``2001 Water 
Quality for the Protection of Human Health: Methylmercury,'' and in the 
IRIS summary for MeHg: ``Rather than choose a single measure for the 
RfD critical endpoint, EPA based this RfD for this assessment on 
several scores from the Faroes' measures, with supporting analyses from 
the New Zealand study, and the integrative analysis of all three 
studies.'' \35\
---------------------------------------------------------------------------

    \35\ EPA, 2001.
---------------------------------------------------------------------------

    EPA defined the updated RfD of 0.0001 mg/kg-day in 2001. Although 
derived from a more complete data set and with a somewhat different 
methodology, the current RfD is numerically the same as the previous 
(1995) RfD (0.0001 mg/kg-day, or 0.1 [micro]g/kg-day).
    This RfD, consistent with the standard definition, is an estimate 
(with uncertainty spanning perhaps an order of magnitude) of a daily 
exposure to the human population (including sensitive subgroups) that 
is likely to be without an appreciable risk of deleterious effects 
during a lifetime (EPA, 2002). In general EPA believes that exposures 
at or below the RfD are unlikely to be associated with appreciable risk 
of deleterious effects. However, no RfD defines an exposure level 
corresponding to zero risk; moreover the RfD does not represent a 
bright line, above which individuals are at risk of adverse effects. 
EPA's interpretation for this assessment is that any exposures to MeHg 
above the RfD are of concern given the nature of the data available for 
Hg that is not necessarily available for many other chemicals. The 
scientific basis for the Hg RfD includes extensive human data and 
extensive data on sensitive subpopulations, including pregnant mothers; 
therefore, the RfD does not include extrapolations from animals to 
humans, and from the general population to sensitive subpopulations. In 
addition, there was no evidence of a threshold for MeHg-related 
neurotoxicity within the range of exposures in the Faroe Islands study 
which served as the primary basis for the RfD. This additional 
confidence in the basis for the RfD suggests that all exposures above 
the RfD can be interpreted with more confidence as causing a potential 
hazard to public health. Studies published since the current MeHg RfD 
was released include new analyses of children's neuropsychological 
effects from the existing Seychelles and Faroe Islands cohorts, 
including formation of a new cohort in the Faroe Islands study. There 
are also a number of new studies that were conducted in population-
based cohorts in the U.S and other countries. A comprehensive 
assessment of the new literature has not been completed by EPA. 
However, 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 Faroes. 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.
ii. Neurologic Effects
    In its review of the literature, the NAS found neurodevelopmental 
effects to be the most sensitive and best documented endpoints and 
appropriate for establishing an RfD;\36\ in particular NAS

[[Page 25001]]

supported the use of results from neurobehavioral or neuropsychological 
tests. The NAS report \37\ noted that studies in animals reported 
sensory effects as well as effects on brain development and memory 
functions and support the conclusions based on epidemiology studies. 
The NAS noted that their recommended endpoints for an RfD are 
associated with the ability of children to learn and to succeed in 
school. They concluded the following: ``The population at highest risk 
is the children of women who consumed large amounts of fish and seafood 
during pregnancy. The committee concludes that the risk to that 
population is likely to be sufficient to result in an increase in the 
number of children who have to struggle to keep up in school.''
---------------------------------------------------------------------------

    \36\ NAS, 2000.
    \37\ NAS, 2000.
---------------------------------------------------------------------------

iii. Cardiovascular Impacts
    The NAS summarized data on cardiovascular effects available up to 
2000 (IRIS 2001). Based on these and other studies, the NRC (2000) 
concluded that ``Although the data base is not as extensive for 
cardiovascular effects as it is for other end points (i.e., neurologic 
effects) the cardiovascular system appears to be a target for MeHg 
toxicity in humans and animals.'' The NRC also stated that ``additional 
studies are needed to better characterize the effect of methylmercury 
exposure on blood pressure and cardiovascular function at various 
stages of life.''
    Additional cardiovascular studies have been published since 2000. 
EPA did not to develop a quantitative dose-response assessment for 
cardiovascular effects associated with MeHg exposures, as there is no 
consensus among scientists on the dose-response functions for these 
effects. In addition, there is inconsistency among available studies as 
to the association between MeHg exposure and various cardiovascular 
system effects. The pharmacokinetics of some of the exposure measures 
(such as toenail Hg levels) are not well understood. The studies have 
not yet received the review and scrutiny of the more well-established 
neurotoxicity data base.
iv. Genotoxic Effects
    The Mercury Study noted that MeHg is not a potent mutagen but is 
capable of causing chromosomal damage in a number of experimental 
systems. The NAS concluded that evidence that human exposure to MeHg 
caused genetic damage is inconclusive; they note that some earlier 
studies showing chromosomal damage in lymphocytes may not have 
controlled sufficiently for potential confounders. One study of adults 
living in the Tapaj[oacute]s River region in Brazil \38\ reported a 
direct relationship between MeHg concentration in hair and DNA damage 
in lymphocytes; as well as effects on chromosomes. Long-term MeHg 
exposures in this population were believed to occur through consumption 
of fish, suggesting that genotoxic effects (largely chromosomal 
aberrations) may result from dietary, chronic MeHg exposures similar to 
and above those seen in the Faroes and Seychelles populations.
---------------------------------------------------------------------------

    \38\ Amorim, M.I., Mergler, D., Bahia, M.O., Dubeau, H., 
Miranda, D., Lebel, J., Burbano, R.R., Lucotte, M., 2000. 
Cytogenetic damage related to low levels of methyl mercury 
contamination in the Brazilian Amazon. An. Acad. Bras. Cienc. 72, 
487-507.
---------------------------------------------------------------------------

v. Immunotoxic Effects
    Although exposure to some forms of Hg can result in a decrease in 
immune activity or an autoimmune response,\39\ evidence for immunotoxic 
effects of MeHg is limited.\40\
---------------------------------------------------------------------------

    \39\ Agency for Toxic Substances and Disease Registry (ATSDR). 
1999. Toxicological profile for Mercury. Atlanta, GA: U.S. 
Department of Health and Human Services, Public Health Service. 
http://www.atsdr.cdc.gov/toxprofiles/tp.asp?id=115&tid=24.
    \40\ National Academy of Sciences. Toxicologic effects of 
methylmercury. Washington, DC: National Research Council, 2000. 
Available online at http://www.nap.edu/openbook.php?isbn=0309071402.
---------------------------------------------------------------------------

vi. Other 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) \41\ and in IRIS.\42\ 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 \43\).
---------------------------------------------------------------------------

    \41\ IARC, 1994.
    \42\ EPA, 2002.
    \43\ NAS, 2000.
---------------------------------------------------------------------------

    There is also some evidence of reproductive and renal toxicity in 
humans from MeHg exposure. However, overall, human data regarding 
reproductive, renal, and hematological toxicity from MeHg are very 
limited and are based on either studies of the two high-dose poisoning 
episodes in Iraq and Japan or animal data, rather than epidemiological 
studies of chronic exposures at the levels of interest in this 
analysis.
b. Mercury Emissions
    Mercury is an element. There is a fixed amount of it in the world. 
As long as it is bound up, for example in coal, it cannot affect people 
or the environment. Once it is released, for example via the combustion 
process, it enters the environment and becomes available for chemical 
conversion. Once emitted, Hg remains in the environment, and can 
bioaccumulate in organisms or be remitted through natural processes. 
Mercury is emitted through natural and anthropogenic processes; in 
addition, previously deposited Hg from either process may be re-
emitted. Mercury deposition in the U.S. is not directly proportional to 
total Hg emissions, due to the differing rates at which the three 
species of Hg (Hg\0\, Hg\+2\, Hgp) deposit. In general, the 
greater the fraction of total Hg accounted for by Hg\+2\ and 
HgP, the higher the correlation between total Hg emissions 
and total Hg deposition in the U.S. In the following discussion, we 
will be describing emissions of Hg, while we discuss deposition later 
in this section.
    The categories for anthropogenic Hg emissions include the 
combustion of fossil-fuels, cement production, waste incineration, 
metals production, and other industrial processes. Anthropogenic Hg 
emissions consist of Hg\0\, Hg\+2\, and HgP.
    Mercury re-emissions include previously deposited Hg originating 
from both natural and anthropogenic sources. At this time, it is not 
possible to determine the original source of previously deposited Hg, 
whether its source is natural emissions or re-emissions from previously 
deposited anthropogenic Hg.44 45 46 It is believed that half 
of re-emitted Hg originates from anthropogenic sources.47 48
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    \44\ Lindberg, S., Bullock, R., Ebinghaus, R., Engstrom, D., 
Feng, X., Fitzgerald, W., et al. (2007). A Synthesis of Progress and 
Uncertainties in Attributing the Sources of Mercury in Deposition. 
Ambio, 36(1), 19-33.
    \45\ Lohman, K., Seigneur, C., Gustin, M., & Lindberg, S. 
(2008). Sensitivity of the global atmospheric cycle of mercury to 
emissions. Applied Geochemistry, 23(3), 454-466.
    \46\ Seigneur, C., Vijayaraghavan, K., Lohman, K., 
Karamchandani, P., & Scott, C. (2004). Global Source Attribution for 
Mercury Speciation in the United States. Environmental Science and 
Technology(38), 555-569.
    \47\ Mason, R., Pirrone, N., & Mason, R. P. (2009). Mercury 
emissions from natural processes and their importance in the global 
mercury cycle. In Mercury Fate and Transport in the Global 
Atmosphere (pp. 173-191): Springer U.S.
    \48\ Selin, N. E., Jacob, D. J., Park, R. J., Yantosca, R. M., 
Strode, S., Jaegl[eacute], L., et al. (2007). Chemical cycling and 
deposition of atmospheric mercury: Global constraints from 
observations. J. Geophys. Res, 112, 1071-1077.
---------------------------------------------------------------------------

    Current estimates of total global Hg emissions based on a 2005 
inventory

[[Page 25002]]

range from 7,300 to 8,300 tpy.49 50 The United Nations 
Environment Programme (UNEP) estimates of 2005 global Hg emissions are 
somewhat lower, at 5,600 metric tpy.\51\ Global anthropogenic Hg 
emissions, excluding biomass burning, have been estimated by many 
researchers. UNEP's 2005 estimate is approximately 2,100 tpy (with a 
range of 1,300 tpy to 3,300 tpy) \52\ and Pirrone, et al.'s 2005 
estimate is approximately 2,600 tpy. Global fossil-fuel fired EGUs 
total approximately 500 to 900 tpy, a large fraction (25 to 35 percent) 
of the total global anthropogenic emissions.53 54 The U.S. 
contribution to global anthropogenic emissions has declined from 10 
percent in 1990 to 5 percent in 2005, due to reductions in U.S. 
emissions and increases in emissions from other countries.\55\
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    \49\ Lindberg, S., Bullock, R., Ebinghaus, R., Engstrom, D., 
Feng, X., Fitzgerald, W., et al. (2007). A Synthesis of Progress and 
Uncertainties in Attributing the Sources of Mercury in Deposition. 
Ambio, 36(1), 19-33.
    \50\ Pirrone, N., Cinnirella, S., Feng, X., Finkelman, R. B., 
Friedli, H. R., Leaner, J., et al. (2010). Global mercury emissions 
to the atmosphere from anthropogenic and natural sources. 
Atmospheric Chemistry and Physics Discussions, 10(2), 4719-4752.
    \51\ UNEP (United Nations Environment Programme), Chemicals 
Branch, 2008. The Global Atmospheric Mercury Assessment: Sources, 
Emissions and Transport, UNEP Chemicals, Geneva.
    \52\ Study on Mercury Sources and Emissions and Analysis of the 
Cost and Effectiveness of Control Measures ``UNEP Paragraph 29 
study'', UNEP (DTIE)/Hg/INC.2/4. November, 2010.
    \53\ Pirrone, N., Cinnirella, S., Feng, X., Finkelman, R. B., 
Friedli, H. R., Leaner, J., et al. (2010). Global mercury emissions 
to the atmosphere from anthropogenic and natural sources. 
Atmospheric Chemistry and Physics Discussions, 10(2), 4719-4752.
    \54\ Study on Mercury Sources and Emissions and Analysis of the 
Cost and Effectiveness of Control Measures ``UNEP Paragraph 29 
study'', UNEP (DTIE)/Hg/INC.2/4. November, 2010.
    \55\ The estimate of 5 percent is based upon 105 tons in 2005 
divided by 2,100 tons from UNEP.
---------------------------------------------------------------------------

    Although total U.S. anthropogenic Hg has decreased, the EGU sector 
remains the largest contributor to the total. In 1990, U.S. EGU Hg 
emissions for coal-fired units above 25 MW were 46 tons out of total 
U.S. Hg emissions of 264 tons.\56\ By 1999 U.S. EGU Hg emissions for 
coal-fired units above 25 MW were 43 out of 115 tons.\57\ In 2005, 
estimated emissions for coal- and oil-fired units above 25 MW were 53 
tons out of a total of 105 tons. However, the 2005 estimate is based on 
control configurations as of 2002; therefore, it does not reflect 
reductions due to control installations that took place between 2002 
and 2005. A current estimate of Hg emissions for both coal- and oil-
fired units above 25 MW, using data from the EPA's 2010 ICR database, 
which used testing data for over 300 units, is 29 tons of Hg. We 
believe our estimate of the current level of Hg emissions based on the 
2010 ICR database may underestimate total EGU Hg emissions due to the 
fact that emission factors used to develop the estimates may not 
accurately account for larger emissions from units with more poorly 
performing emission controls. EPA tested only 50 randomly selected 
units that were not selected for testing as best performing units (the 
bottom 85 percent of units), and we used that small sample to attempt 
to characterize the lower performing units. Because the 50 units were 
randomly selected, we do not believe we have sufficiently characterized 
the units that have poorly performing controls. In addition, the 2010 
estimate also reflects the installation of Hg controls to comply with 
state Hg-specific rules, voluntary reductions from EGUs, and the co-
benefits of Hg reductions associated with control devices installed for 
the reduction of SO2 and PM as a result of state and Federal 
actions, such as New Source Review (NSR) enforcement actions and 
implementation of CAIR. Table 3 shows U.S. EGU Hg emissions along with 
emissions from other major non-EGU Hg sources. Table 3 also shows EPA's 
projection that U.S. EGU emissions will continue to comprise a dominant 
portion of the total U.S. anthropogenic inventory in 2016. In 2016, 
U.S. EGU Hg emission for the subset of coal-fired units above 25 MW is 
projected to be 29 tons out of a total of 64 tons.\58\
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    \56\ The 46 ton estimate is based on the Utility Study. Since 
that time, EPA has updated its estimate of U.S. EGU Hg emissions in 
1990. The updated estimate is 59 tons.
    \57\ Since the December 2000 Finding, the NEI process has led to 
an updated emissions estimate of 49 tons.
    \58\ As explained further in the emissions modeling TSD, this 
projection does not include reductions from a number of state-only 
Hg regulations and voluntary Hg reductions programs that are not 
Federally enforceable, and are not relevant to our assessment of 
whether it is appropriate and necessary to regulate U.S. EGU sources 
under section 112.

    Table 3--Anthropogenic Hg Emissions and Projections in The U.S.*
------------------------------------------------------------------------
                                           2005 Mercury    2016 Mercury
                Category                      (tons)          (tons)
------------------------------------------------------------------------
Electric Generating Units...............              53              29
Portland Cement Manufacturing...........             7.5             1.1
Stainless and Nonstainless Steel                     7.0             4.6
 Manufacturing: Electric Arc Furnaces...
Industrial, Commercial, Institutional                6.4             4.6
 Boilers & Process Heaters..............
Chemical Manufacturing..................             3.3             3.3
Hazardous Waste Incineration............             3.2             2.1
Mercury Cell Chlor-Alkali Plants........             3.1             0.3
Gold Mining.............................             2.5             0.7
Municipal Waste Combustors..............             2.3             2.3
Sum of other source categories (each of               17              16
 which emits less than 2 tons)..........
                                         -------------------------------
    Total...............................             105              64
------------------------------------------------------------------------
* Emissions estimates are presented at a maximum of two significant
  figures.

c. Atmospheric Processing and Deposition of Hg
    Mercury is known to exist in the atmosphere in three forms: Hg\0\, 
Hg\+2\, and HgP. The dominant form of Hg in the atmosphere 
is Hg\0\.\59\ Elemental Hg dominates total Hg composition in the 
atmosphere (greater than 95 percent) and has a much greater residence 
time than Hg\+2\ or HgP. Elemental Hg has a long atmospheric 
residence time due to its near insolubility in water and high vapor 
pressure which minimize removal through wet and dry deposition 
processes.\60\ Oxidized Hg (which is

[[Page 25003]]

soluble) and HgP are more readily scavenged by precipitation 
and have higher dry deposition velocities than Hg\0\ resulting in much 
shorter residence times. Although natural sources such as land, ocean 
and volcanic Hg are emitted as elemental, most anthropogenic sources 
are emitted in all three forms. EGU Hg ranges from 20 to 40 percent 
Hg\+2\ and from 2 to 5 percent Hgp. This results in greater 
deposition of Hg\+2\ and HgP within the U.S. due to U.S. EGU 
emissions of these two Hg species, relative to emissions of Hg\0\. As a 
result, control of emissions of Hg\+2\ and HgP are more 
relevant for decreasing U.S. EGU-attributable exposures to MeHg for 
recreational and subsistence-level fish consumers than control of 
emissions of Hg\0\. Control of emissions of Hg\0\ will still have value 
in reducing overall global levels of Hg deposition, and will, all else 
equal, eventually result in lower global fish MeHg concentrations which 
can benefit both U.S. and global populations.
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    \59\ Schroeder, W. H. and J. Munthe (1998). ``Atmospheric 
mercury--An overview.'' Atmospheric Environment 32(5): 809-822.
    \60\ Schroeder, W. H. and J. Munthe (1998). ``Atmospheric 
mercury--An overview.'' Atmospheric Environment 32(5): 809-822.
    Marsik, F. J., G. J. Keeler, et al. (2007). ``The dry-deposition 
of speciated mercury to the Florida Everglades: Measurements and 
modeling.'' Atmospheric Environment 41(1): 136-149.
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2. Background Information on Non-Hg HAP Emissions and Effects on Human 
Health and the Environment
a. Overview of Non-Hg HAP and Associated Health and Environmental 
Hazards
    Emissions data collected through the 2010 ICR during development of 
this proposed rule show that HCl emissions represent the predominant 
HAP emitted by U.S. EGUs. Coal- and oil-fired EGUs emit lesser amounts 
of HF, chlorine (Cl2), metals (As, Cd, Cr, Hg, Mn, Ni, and 
Pb), and organic HAP emissions. Although numerous organic HAP may be 
emitted from coal- and oil-fired EGUs, only a few account for 
essentially all the mass of organic HAP emissions. These organic HAP 
are formaldehyde, benzene, and acetaldehyde.
    Exposure to high levels of the various non-Hg HAP emitted by EGUs 
is associated with a variety of adverse health effects. These adverse 
health effects include chronic (long-term) health disorders (e.g., 
effects on the central nervous system, damage to the kidneys, and 
irritation of the lung, skin, and mucus membranes); and acute health 
disorders (e.g., effects on the kidney and central nervous system, 
alimentary effects such as nausea and vomiting, and lung irritation and 
congestion). EPA has classified three of the HAP emitted by EGUs as 
human carcinogens and five as probable human carcinogens. The following 
sections briefly discuss the main health effects information we have 
regarding the key HAP emitted by EGUs in alphabetical order by HAP 
name.
i. Acetaldehyde
    Acetaldehyde is classified in EPA's IRIS database as a probable 
human carcinogen, based on nasal tumors in rats, and is considered 
toxic by the inhalation, oral, and intravenous routes.\61\ Acetaldehyde 
is reasonably anticipated to be a human carcinogen by the U.S. 
Department of Health and Human Services (DHHS) in the 11th Report on 
Carcinogens and is classified as possibly carcinogenic to humans (Group 
2B) by the IARC.62 63 The primary noncancer effects of 
exposure to acetaldehyde vapors include irritation of the eyes, skin, 
and respiratory tract.\64\
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    \61\ U.S. Environmental Protection Agency (U.S. EPA). 1991. 
Integrated Risk Information System File of Acetaldehyde. Research 
and Development, National Center for Environmental Assessment, 
Washington, DC. This material is available electronically at http://www.epa.gov/iris/subst/0290.htm.
    \62\ U.S. Department of Health and Human Services National 
Toxicology Program 11th Report on Carcinogens available at: http://ntp.niehs.nih.gov/go/16183.
    \63\ International Agency for Research on Cancer (IARC). 1999. 
Re-evaluation of some organic chemicals, hydrazine, and hydrogen 
peroxide. IARC Monographs on the Evaluation of Carcinogenic Risk of 
Chemical to Humans, Vol 71. Lyon, France.
    \64\ U.S. Environmental Protection Agency (U.S. EPA). 1991. 
Integrated Risk Information System File of Acetaldehyde. Research 
and Development, National Center for Environmental Assessment, 
Washington, DC. This material is available electronically at http://www.epa.gov/iris/subst/0290.htm.
---------------------------------------------------------------------------

ii. Arsenic
    Arsenic, a naturally occurring element, is found throughout the 
environment and is considered toxic through the oral, inhalation and 
dermal routes. Acute (short-term) high-level inhalation exposure to As 
dust or fumes has resulted in gastrointestinal effects (nausea, 
diarrhea, abdominal pain, and gastrointestinal hemorrhage); central and 
peripheral nervous system disorders have occurred in workers acutely 
exposed to inorganic As. Chronic (long-term) inhalation exposure to 
inorganic As in humans is associated with irritation of the skin and 
mucous membranes. Chronic inhalation can also lead to conjunctivitis, 
irritation of the throat and respiratory tract and perforation of the 
nasal septum.\65\ Chronic oral exposure has resulted in 
gastrointestinal effects, anemia, peripheral neuropathy, skin lesions, 
hyperpigmentation, and liver or kidney damage in humans. Inorganic As 
exposure in humans, by the inhalation route, has been shown to be 
strongly associated with lung cancer, while ingestion of inorganic As 
in humans has been linked to a form of skin cancer and also to bladder, 
liver, and lung cancer. EPA has classified inorganic As as a Group A, 
human carcinogen.\66\
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    \65\ Agency for Toxic Substances and Disease Registry (ATSDR). 
Medical Management Guidelines for Arsenic. Atlanta, GA: U.S. 
Department of Health and Human Services. Available on the Internet 
at http://www.atsdr.cdc.gov/mhmi/mmg168.html#bookmark02.
    \66\ U.S. Environmental Protection Agency (U.S. EPA). 1998. 
Integrated Risk Information System File for Arsenic. Research and 
Development, National Center for Environmental Assessment, 
Washington, DC. This material is available electronically at: http://www.epa.gov/iris/subst/0278.htm.
---------------------------------------------------------------------------

iii. Benzene
    The EPA's IRIS database lists benzene as a known human carcinogen 
(causing leukemia) by all routes of exposure, and concludes that 
exposure is associated with additional health effects, including 
genetic changes in both humans and animals and increased proliferation 
of bone marrow cells in mice.67 68 69 EPA states in its IRIS 
database that data indicate a causal relationship between benzene 
exposure and acute lymphocytic leukemia and suggest a relationship 
between benzene exposure and chronic non-lymphocytic leukemia and 
chronic lymphocytic leukemia. The IARC has determined that benzene is a 
human carcinogen and the DHHS has characterized benzene as a known 
human carcinogen.70 71
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    \67\ U.S. Environmental Protection Agency (U.S. EPA). 2000. 
Integrated Risk Information System File for Benzene. Research and 
Development, National Center for Environmental Assessment, 
Washington, DC. This material is available electronically at: http://www.epa.gov/iris/subst/0276.htm.
    \68\ International Agency for Research on Cancer, IARC 
monographs on the evaluation of carcinogenic risk of chemicals to 
humans, Volume 29, Some industrial chemicals and dyestuffs, 
International Agency for Research on Cancer, World Health 
Organization, Lyon, France, p. 345-389, 1982.
    \69\ Irons, R.D.; Stillman, W.S.; Colagiovanni, D.B.; Henry, 
V.A. (1992) Synergistic action of the benzene metabolite 
hydroquinone on myelopoietic stimulating activity of granulocyte/
macrophage colony-stimulating factor in vitro, Proc. Natl. Acad. 
Sci. 89:3691-3695.
    \70\ International Agency for Research on Cancer (IARC). 1987. 
Monographs on the evaluation of carcinogenic risk of chemicals to 
humans, Volume 29, Supplement 7, Some industrial chemicals and 
dyestuffs, World Health Organization, Lyon, France.
    \71\ U.S. Department of Health and Human Services National 
Toxicology Program 11th Report on Carcinogens available at: http://ntp.niehs.nih.gov/go/16183.
---------------------------------------------------------------------------

    A number of adverse noncancer health effects including blood 
disorders, such as preleukemia and aplastic anemia, have also been 
associated with long-term exposure to benzene.72 73
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    \72\ Aksoy, M. (1989). Hematotoxicity and carcinogenicity of 
benzene. Environ. Health Perspect. 82: 193-197.
    \73\ Goldstein, B.D. (1988). Benzene toxicity. Occupational 
medicine. State of the Art Reviews. 3: 541-554.

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[[Page 25004]]

iv. Cadmium
    Breathing air with lower levels of Cd over long periods of time 
(for years) results in a build-up of Cd in the kidney, and if 
sufficiently high, may result in kidney disease. Lung cancer has been 
found in some studies of workers exposed to Cd in the air and studies 
of rats that inhaled Cd. DHHS has determined that Cd and Cd compounds 
are known human carcinogens. IARC has determined that Cd is 
carcinogenic to humans. EPA has determined that Cd is a probable human 
carcinogen.\74\
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    \74\ Agency for Toxic Substances and Disease Registry (ATSDR). 
2008. Public Health Statement for Cadmium. CAS 1306-19-0. 
Atlanta, GA: U.S. Department of Health and Human Services, Public 
Health Service. Available on the Internet at http://www.atsdr.cdc.gov/PHS/PHS.asp?id=46&tid=15.
---------------------------------------------------------------------------

v. Chlorine
    The acute (short term) toxic effects of Cl2 are 
primarily due to its corrosive properties. Chlorine is a strong oxidant 
that upon contact with water moist tissue (e.g., eyes, skin, and upper 
respiratory tract) can produce major tissue damage.\75\ Chronic 
inhalation exposure to low concentrations of Cl2 (1 to 10 
parts per million, ppm) may cause eye and nasal irritation, sore 
throat, and coughing. Chronic exposure to Cl2, usually in 
the workplace, has been reported to cause corrosion of the teeth. 
Inhalation of higher concentrations of Cl2 gas (greater than 
15 ppm) can rapidly lead to respiratory distress with airway 
constriction and accumulation of fluid in the lungs (pulmonary edema). 
Exposed individuals may have immediate onset of rapid breathing, blue 
discoloration of the skin, wheezing, rales or hemoptysis (coughing up 
blood or blood-stain sputum). Intoxication with high concentrations of 
Cl2 may induce lung collapse. Exposure to Cl2 can 
lead to reactive airways dysfunction syndrome (RADS), a chemical 
irritant-induced type of asthma. Dermal exposure to Cl2 may 
cause irritation, burns, inflammation and blisters. EPA has not 
classified Cl2 with respect to carcinogenicity.
---------------------------------------------------------------------------

    \75\ Agency for Toxic Substances and Disease Registry (ATSDR). 
Medical Management Guidelines for Chlorine. Atlanta, GA: U.S. 
Department of Health and Human Services. http://www.atsdr.cdc.gov/mmg/mmg.asp?id=198&tid=36.
---------------------------------------------------------------------------

vi. Chromium
    Chromium may be emitted in two forms, trivalent Cr (Cr\+3\) or 
hexavalent Cr (Cr\+6\). The respiratory tract is the major target organ 
for Cr\+6\ toxicity, for acute and chronic inhalation exposures. 
Shortness of breath, coughing, and wheezing have been reported from 
acute exposure to Cr\+6\, while perforations and ulcerations of the 
septum, bronchitis, decreased pulmonary function, pneumonia, and other 
respiratory effects have been noted from chronic exposures. Limited 
human studies suggest that Cr\+6\ inhalation exposure may be associated 
with complications during pregnancy and childbirth, but there are no 
supporting data from animal studies reporting reproductive effects from 
inhalation exposure to Cr\+6\. Human and animal studies have clearly 
established the carcinogenic potential of Cr\+6\ by the inhalation 
route, resulting in an increased risk of lung cancer. EPA has 
classified Cr\+6\ as a Group A, human carcinogen. Trivalent Cr is less 
toxic than Cr\+6\. The respiratory tract is also the major target organ 
for Cr\+3\ toxicity, similar to Cr\+6\. EPA has not classified Cr\+3\ 
with respect to carcinogenicity.
vii. Formaldehyde
    Since 1987, EPA has classified formaldehyde as a probable human 
carcinogen based on evidence in humans and in rats, mice, hamsters, and 
monkeys.\76\ EPA is currently reviewing recently published 
epidemiological data. After reviewing the currently available 
epidemiological evidence, the IARC (2006) characterized the human 
evidence for formaldehyde carcinogenicity as ``sufficient,'' based upon 
the data on nasopharyngeal cancers; the epidemiologic evidence on 
leukemia was characterized as ``strong.'' \77\ EPA is reviewing the 
recent work cited above from the National Cancer Institute (NCI) and 
National Institute for Occupational Safety and Health (NIOSH), as well 
as the analysis by the CIIT Centers for Health Research and other 
studies, as part of a reassessment of the human hazard and dose-
response associated with formaldehyde.
---------------------------------------------------------------------------

    \76\ U.S. EPA. 1987. Assessment of Health Risks to Garment 
Workers and Certain Home Residents from Exposure to Formaldehyde, 
Office of Pesticides and Toxic Substances, April 1987.
    \77\ International Agency for Research on Cancer (2006) 
Formaldehyde, 2-Butoxyethanol and 1-tert-Butoxypropan-2-ol. 
Monographs Volume 88. World Health Organization, Lyon, France.
---------------------------------------------------------------------------

    Formaldehyde exposure also causes a range of noncancer health 
effects, including irritation of the eyes (burning and watering of the 
eyes), nose and throat. Effects from repeated exposure in humans 
include respiratory tract irritation, chronic bronchitis and nasal 
epithelial lesions such as metaplasia and loss of cilia. Animal studies 
suggest that formaldehyde may also cause airway inflammation--including 
eosinophil infiltration into the airways. There are several studies 
that suggest that formaldehyde may increase the risk of asthma--
particularly in the young.78 79
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    \78\ Agency for Toxic Substances and Disease Registry (ATSDR). 
1999. Toxicological profile for Formaldehyde. Atlanta, GA: U.S. 
Department of Health and Human Services, Public Health Service. 
http://www.atsdr.cdc.gov/toxprofiles/tp111.html
    \79\ WHO (2002) Concise International Chemical Assessment 
Document 40: Formaldehyde. Published under the joint sponsorship of 
the United Nations Environment Programme, the International Labour 
Organization, and the World Health Organization, and produced within 
the framework of the Inter-Organization Programme for the Sound 
Management of Chemicals. Geneva.
---------------------------------------------------------------------------

viii. Hydrogen Chloride
    Hydrogen chloride is a corrosive gas that can cause irritation of 
the mucous membranes of the nose, throat, and respiratory tract. Brief 
exposure to 35 ppm causes throat irritation, and levels of 50 to 100 
ppm are barely tolerable for 1 hour.\80\ The greatest impact is on the 
upper respiratory tract; exposure to high concentrations can rapidly 
lead to swelling and spasm of the throat and suffocation. Most 
seriously exposed persons have immediate onset of rapid breathing, blue 
coloring of the skin, and narrowing of the bronchioles. Exposure to HCl 
can lead to RADS, a chemically- or irritant-induced type of asthma. 
Children may be more vulnerable to corrosive agents than adults because 
of the relatively smaller diameter of their airways. Children may also 
be more vulnerable to gas exposure because of increased minute 
ventilation per kg and failure to evacuate an area promptly when 
exposed. Hydrogen chloride has not been classified for carcinogenic 
effects.\81\
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    \80\ Agency for Toxic Substances and Disease Registry (ATSDR). 
Medical Management Guidelines for Hydrogen Chloride. Atlanta, GA: 
U.S. Department of Health and Human Services. Available online at 
http://www.atsdr.cdc.gov/mmg/mmg.asp?id=758&tid=147#bookmark02.
    \81\ U.S. Environmental Protection Agency (U.S. EPA). 1995. 
Integrated Risk Information System File of Hydrogen Chloride. 
Research and Development, National Center for Environmental 
Assessment, Washington, DC. This material is available 
electronically at http://www.epa.gov/iris/subst/0396.htm.
---------------------------------------------------------------------------

ix. Hydrogen Fluoride
    Acute (short-term) inhalation exposure to gaseous HF can cause 
severe respiratory damage in humans, including severe irritation and 
pulmonary edema. Chronic (long-term) oral exposure to fluoride at low 
levels has a beneficial effect of dental cavity prevention and may also 
be useful for the treatment of osteoporosis. Exposure to higher levels 
of fluoride may cause dental fluorosis. One study reported

[[Page 25005]]

menstrual irregularities in women occupationally exposed to fluoride 
via inhalation. The EPA has not classified HF for carcinogenicity.\82\
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    \82\ U.S. Environmental Protection Agency. Health Issue 
Assessment: Summary Review of Health Effects Associated with 
Hydrogen Fluoride and Related Compounds. EPA/600/8-89/002F. 
Environmental Criteria and Assessment Office, Office of Health and 
Environmental Assessment, Office of Research and Development, 
Cincinnati, OH. 1989.
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x. Lead
    The main target for Pb toxicity is the nervous system, both in 
adults and children. Long-term exposure of adults to Pb at work has 
resulted in decreased performance in some tests that measure functions 
of the nervous system. Lead exposure may also cause weakness in 
fingers, wrists, or ankles. Lead exposure also causes small increases 
in blood pressure, particularly in middle-aged and older people. Lead 
exposure may also cause anemia.
    Children are more sensitive to the health effects of Pb than 
adults. No safe blood Pb level in children has been determined. At 
lower levels of exposure, Pb can affect a child's mental and physical 
growth. Fetuses exposed to Pb in the womb may be born prematurely and 
have lower weights at birth. Exposure in the womb, in infancy, or in 
early childhood also may slow mental development and cause lower 
intelligence later in childhood. There is evidence that these effects 
may persist beyond childhood.\83\
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    \83\ Agency for Toxic Substances and Disease Registry (ATSDR). 
2007. Public Health Statement for Lead. CAS: 7439-92-1. 
Atlanta, GA: U.S. Department of Health and Human Services, Public 
Health Service. Available on the Internet at http://www.atsdr.cdc.gov/ToxProfiles/phs13.html.
---------------------------------------------------------------------------

    There are insufficient data from epidemiologic studies alone to 
conclude that Pb causes cancer (is carcinogenic) in humans. DHHS has 
determined that Pb and Pb compounds are reasonably anticipated to be 
human carcinogens based on limited evidence from studies in humans and 
sufficient evidence from animal studies, and EPA has determined that Pb 
is a probable human carcinogen.
xi. Manganese
    Health effects in humans have been associated with both 
deficiencies and excess intakes of Mn. Chronic exposure to high levels 
of Mn by inhalation in humans results primarily in central nervous 
system effects. Visual reaction time, hand steadiness, and eye-hand 
coordination were affected in chronically-exposed workers. Manganism, 
characterized by feelings of weakness and lethargy, tremors, a masklike 
face, and psychological disturbances, may result from chronic exposure 
to higher levels. Impotence and loss of libido have been noted in male 
workers afflicted with manganism attributed to inhalation exposures. 
The EPA has classified Mn in Group D, not classifiable as to 
carcinogenicity in humans.\84\
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    \84\ U.S. Environmental Protection Agency. Integrated Risk 
Information System (IRIS) on Manganese. National Center for 
Environmental Assessment, Office of Research and Development, 
Washington, DC. 1999.
---------------------------------------------------------------------------

xii. Nickel
    Respiratory effects have been reported in humans from inhalation 
exposure to Ni. No information is available regarding the reproductive 
or developmental effects of Ni in humans, but animal studies have 
reported such effects. Human and animal studies have reported an 
increased risk of lung and nasal cancers from exposure to Ni refinery 
dusts and nickel subsulfide. The EPA has classified nickel subsulfide 
as a human carcinogen and nickel carbonyl as a probable human 
carcinogen.85 86 The IARC has classified Ni compounds as 
carcinogenic to humans.\87\
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    \85\ U.S. Environmental Protection Agency. Integrated Risk 
Information System (IRIS) on Nickel Subsulfide. National Center for 
Environmental Assessment, Office of Research and Development, 
Washington, DC. 1999.
    \86\ U.S. Environmental Protection Agency. Integrated Risk 
Information System (IRIS) on Nickel Carbonyl. National Center for 
Environmental Assessment, Office of Research and Development, 
Washington, DC. 1999.
    \87\ Nickel (IARC Summary & Evaluation, Volume 49, 1990), http://www.inchem.org/documents/iarc/vol49/nickel.html.
---------------------------------------------------------------------------

xiii. Selenium
    Acute exposure to elemental Se, hydrogen selenide, and selenium 
dioxide (SeO2) by inhalation results primarily in 
respiratory effects, such as irritation of the mucous membranes, 
pulmonary edema, severe bronchitis, and bronchial pneumonia. One Se 
compound, selenium sulfide, is carcinogenic in animals exposed orally. 
EPA has classified elemental Se as a Group D, not classifiable as to 
human carcinogenicity, and selenium sulfide as a Group B2, probable 
human carcinogen.
b. Non-Hg HAP Emissions
    Fossil-fuel fired boilers emit a variety of metal HAP, organic HAP 
and HAP that are acid gases. Acid gas and metal HAP emissions are 
discussed below.
i. Acid Gases
    Based on the 2010 ICR and the National Air Toxics Assessment (NATA) 
inventory estimates of acid gas emissions, U.S. EGUs emit the majority 
of HCl and HF nationally, supporting EPA's view that it remains 
appropriate to regulate HAP from U.S. EGUs. Acid gas emissions from 
EGUs include HCl, HF, Cl2, and HCN. These pollutants are 
emitted as a result of fluorine, chlorine, and nitrogen components of 
the fuels. Table 4 of this preamble shows emissions of certain acid 
gases from EGUs, based on the 2005 NATA inventory. 2010 estimates of 
emissions for acid HAP from U.S. EGU are 7,900 tpy for HCN, 106,000 
tons for HCl, and 36,000 tons for HF.\88\
---------------------------------------------------------------------------

    \88\ We believe our estimate of the current level of acid HAP 
emissions based on the 2010 ICR database may underestimate total EGU 
acid HAP emissions due to targeting of the 2010 ICR on the best 
performing EGUs.

                             Table 4--Summary of Acid Gas Emissions From EGU Sources
----------------------------------------------------------------------------------------------------------------
                                                                   2005 Acid HAP emissions from     Percent of
                                                                      the National Air Toxics       total U.S.
                                                                      Assessment (NATA) (tpy)      anthropogenic
                                                                 --------------------------------  emissions in
                                                                                                       2005
                                                                     U.S. EGU      U.S. Non-EGU  ---------------
                                                                     emissions       emissions        Non-EGU
                                                                                                     emissions
----------------------------------------------------------------------------------------------------------------
Hydrogen Cyanide\1\.............................................           1,200          14,000               8
Hydrogen Chloride...............................................         350,000          78,000              82
Hydrogen Fluoride...............................................          47,000          28,000              62
----------------------------------------------------------------------------------------------------------------
\1\ Using cyanide emissions for HCN.


[[Page 25006]]

ii. Metal HAP
    U.S. EGUs are the predominant source of emissions nationally for 
many metal HAP, including Sb, As, Cr, Co, and Se.
    Metals are emitted primarily because they are present in fuels. 
Table 5 of this preamble shows selected metals emitted by EGUs and 
emission estimates based on data from the 2005 NATA inventory. 2010 
estimates of metal HAP emissions are 25 tpy for antimony (Sb), 43 tpy 
for As, 2 tpy for Be, 3 tpy for Cd, 222 tpy for Cr, 19 tpy for Co, 183 
tpy for Mn, 387 tpy for Ni, and 258 tpy for Se.\89\ Depending on the 
metal, EGUs account for between 13 and 83 percent of national metal HAP 
emissions, and as a result it remains appropriate to regulate EGUs.
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    \89\ We believe our estimate of the current level of metal HAP 
emissions based on the 2010 ICR database may underestimate total EGU 
metal HAP emissions due to targeting of the 2010 ICR on the best 
performing EGUs.

                              Table 5--Summary of Metal Emissions From EGU Sources
----------------------------------------------------------------------------------------------------------------
                                                                  2005 Metal HAP emissions from
                                                                   the inventory used for the       Percent of
                                                                 National Air Toxics Assessment     total U.S.
                                                                          (NATA) (tpy)            anthropogenic
                                                                --------------------------------   emissions in
                                                                    U.S. EGU      U.S. Non-EGU         2005
                                                                    emissions       emissions
----------------------------------------------------------------------------------------------------------------
Antimony.......................................................              19              83               19
Arsenic........................................................             200             120               62
Beryllium......................................................              10              13               44
Cadmium........................................................              25              38               39
Chromium.......................................................             120             430               22
Cobalt.........................................................              54              60               47
Manganese......................................................             270           1,800               13
Nickel.........................................................             320             840               28
Selenium.......................................................             580             120               83
----------------------------------------------------------------------------------------------------------------

3. Quantitative Risk Characterizations To Inform the Appropriate and 
Necessary Finding
    EPA conducted quantitative risk analyses to evaluate the extent of 
risk posed by emissions of HAP from U.S. EGUs. These analyses 
demonstrate that U.S. EGU HAP emissions do create the potential for 
risks to the public health, as described below.
a. Scope of Quantitative Risk Analyses
    To evaluate the potential for public health hazards from emissions 
of Hg and non-Hg HAP from U.S. EGUs, EPA conducted quantitative risk 
analyses using several methods intended to address specific risk-
related questions.90 91 Outputs from this assessment 
include: (1) The potential exposures to MeHg and risks associated with 
current U.S. EGU Hg emissions for populations most likely to be at risk 
from exposure to MeHg associated with U.S. EGU Hg emissions; (2) excess 
deposition of Hg in nearby locations within 50 kilometers (km) of EGUs 
that might result in Hg deposition ``hotspots''; (3) for populations 
living in the vicinity of EGUs, the maximum individual risks (MIR) 
associated with U.S. EGU non-Hg HAP emissions, for both cancer and non-
cancer risks, compared to established health benchmarks (e.g., greater 
than one in a million for cancer risks, and a HQ exceeding one for 
chronic non-cancer risks).\92\
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    \90\ U.S. EPA. 2011. Technical Support Document: National-Scale 
Mercury Risk Assessment Supporting the Appropriate and Necessary 
Finding for Coal- and Oil-Fired Electric Generating Units. Office of 
Air Quality Planning and Standards.
    \91\ U.S. EPA. 2011. Technical Support Document: Non-Mercury HAP 
Case Studies Supporting the Appropriate and Necessary Finding for 
Coal- and Oil-Fired Electric Generating Units. Office of Air Quality 
Planning and Standards.
    \92\ The hazard quotient (HQ) is the estimated inhalation or 
ingestion exposure divided by the reference dose (RfD).
---------------------------------------------------------------------------

    To evaluate the potential for health risks associated with U.S. EGU 
Hg emissions, EPA conducted a national scale assessment of the impacts 
of U.S. EGU Hg emissions on exposures to MeHg above the RfD, and as a 
contributor to exposures above the RfD in conjunction with exposures 
from other U.S. and non-U.S. Hg emissions. To evaluate risks of U.S. 
EGU Hg ``hotspots,'' EPA conducted a national scale assessment based on 
the Hg deposition modeling used in the national-scale Hg risk 
assessment. To evaluate inhalation risks of U.S. EGU non-Hg HAP 
emissions, EPA recently conducted 16 case studies at EGUs. EPA selected 
these case studies based on HAP emissions information from the ICR. For 
each case study, EPA estimated the MIR for cancer and non-cancer health 
effects for each HAP emitted by the case study U.S. EGU facility. 
Cancer risks for non-Hg HAP are estimated as the number of excess 
cancer cases per million people. This section briefly describes the 
methods used in the analyses and the results for the national-scale Hg 
risk analysis and the non-Hg HAP inhalation risk case studies.
b. Emissions for Hg and Non-Hg HAP
    The national-scale Hg risk analysis is based on modeling Hg 
deposition associated with 2005 U.S. EGU Hg emissions and 2016 
projected Hg emissions.
    The 2005 base case includes 105 tons of Hg and 430,000 tons of HCl 
from all sources, of which 53 tons of Hg and 350,000 tons of HCl are 
from EGUs. The 2016 projected total Hg emissions from all sources used 
in the risk modeling are 64 tons and HCl emissions are 140,000 tons, 
with 29 tons of Hg and 74,000 tons of HCl from EGUs. U.S. EGU Hg 
emissions accounted for 50 percent of total U.S. Hg emissions in 2005 
and are projected to account for 45 percent of such emissions in 2016. 
Details regarding the emissions used in these analyses are provided in 
the emissions memorandum, ``Emissions Overview: Hazardous Air 
Pollutants in Support of the Proposed Toxics Rule''.\93\
---------------------------------------------------------------------------

    \93\ Strum, M., Houyoux, M., op. cit., Section 4.
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    Between 2005 and 2010, Hg emissions in the U.S. have declined as a 
result of state regulations of Hg or Federal regulatory and enforcement 
actions that required installation of SO2 scrubbers at EGUs 
which decreased Hg emissions.\94\

[[Page 25007]]

The 2010 ICR shows the EGU Hg and HCl totals are lower than in 2005, at 
29 tons and 106,000 tons respectively.
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    \94\ The 2005 estimate is based on control configurations as of 
2002, therefore it does not reflect reductions due to substantial 
control installations that took place between 2002 and 2005. The 
2010 estimates reflect control information reported to EPA as part 
of the recent 2010 ICR in late 2009.
---------------------------------------------------------------------------

    Given that the 2010 emissions for Hg are much closer to the 2016 
projected emissions than to the 2005 emissions, we focus on the results 
from 2016 from the national-scale Hg risk analysis described below, as 
the projected emissions are almost the same as current HAP emissions 
from EGUs.
c. National-Scale Hg Risk Modeling
i. Purpose and Scope of Analysis
    The national-scale risk assessment for Hg focuses on risk 
associated with Hg released from U.S. EGUs that deposits to watersheds 
within the continental U.S., bioaccumulates in fish, and then is 
consumed as MeHg in fish eaten by subsistence fishers and other 
freshwater self-caught fish consumers. The risk assessment is intended 
to assess risk for scenarios representing high-end self-caught fish 
consumers active at inland freshwater lakes and streams. This reflects 
our goal of determining whether U.S. EGUs represent a potential public 
health hazard for the group of fish consumers likely to experience the 
highest risk attributable to U.S. EGUs. In defining the high fish 
consuming populations included in the analysis, we have used 
information from studies of fish consumption to ensure that we have 
identified fisher populations that are likely active to some extent 
across the watersheds included in this analysis (i.e., they are not 
purely hypothetical). The risk assessment considered the magnitude and 
prevalence of the risk to public health posed by current U.S. EGU Hg 
emissions and the remaining risk posed by U.S. EGU Hg emissions after 
imposition of the requirements of the CAA, as described more fully 
below. In both cases, we assess the contribution of U.S. EGUs to 
potential risks from MeHg exposure relative to total MeHg risk 
associated with Hg deposited by other sources both domestic and 
international.
    Risk from Hg exposures occurs primarily through the consumption of 
fish that have bioaccumulated MeHg originally deposited to watersheds 
following atmospheric release and transport. The population that is 
most at risk from consumption of MeHg in fish is children born to 
mothers who were exposed to MeHg during pregnancy through fish 
consumption. The type of fish consumption likely to lead to the 
greatest exposure to MeHg attributable to U.S. EGUs is associated with 
fishing activity at inland freshwater rivers and lakes located in 
regions with elevated U.S. EGU Hg deposition. Thus we focus on MeHg 
exposure to women of childbearing age who consume self-caught 
freshwater fish on a regular basis, e.g., once a day to once every 
several days.
    As noted above, current U.S. EGU Hg emissions as reflected in the 
2010 ICR are closer to 2016 projected emissions than to the 2005 
emissions. For this reason, in discussing risk estimates, we focus on 
the 2016 results rather than the 2005 results.
    The risk assessment compares the U.S. EGU incremental contribution 
to total potential exposure with the RfD and also evaluates the percent 
of total Hg exposures from all sources contributed by U.S. EGUs (i.e., 
the fraction of total risk associated with U.S. EGUs) to individual 
watersheds for which we have fish tissue MeHg data.
    We used this information to assess whether a public health hazard 
is associated with U.S. EGU emissions. Our focus is on women of child-
bearing age in subsistence fishing populations who consume freshwater 
fish that they or their family caught. These populations are likely to 
experience the greatest risk from Hg exposure when fishing at inland 
(freshwater) locations that receive the highest levels of U.S. EGU-
attributable Hg deposition. We also acknowledge that additional 
populations are likely exposed to MeHg from consuming fish caught in 
near-coastal, e.g., estuarine environments. However, there is high 
uncertainty about the relationship of MeHg levels in those fish and 
deposition of Hg from U.S. EGUs, and as such we have not included those 
types of fish consumption in our analysis. However, it is likely that 
the range of potential exposures to U.S. EGU Hg deposition across 
inland watersheds captures the types of potential exposures that occur 
in near-coastal environments, and, thus, likely represents potential 
risks from consumption of fish caught in those environments.
    Consumption rates for the high-end fishing populations included in 
the risk assessment are based on studies in the published literature, 
and are documented in the TSD accompanying this finding.
    We do not estimate risks associated with commercial fish 
consumption because of the expected low contribution of U.S. EGU Hg to 
this type of fish, relative to non-U.S. Hg emissions, and the high 
levels of uncertainty in mapping U.S. EGU Hg emissions to 
concentrations of MeHg in ocean-going fish. The population affected by 
those U.S. EGU Hg emissions that go into the global pool of Hg will 
potentially be much larger than the population of the U.S. Thus, the 
impacts of U.S. EGUs on global exposures to Hg, while highly uncertain, 
adds additional support to the finding that Hg emissions from U.S. EGUs 
pose a hazard to public health.
ii. Risk Characterization Framework
    EPA assessed risk from potential exposure to MeHg through fish 
consumption at a subset of watersheds across the country for which we 
have measured fish tissue MeHg data. This risk assessment uses 
estimates of potential exposure for subsistence fisher populations to 
generate risk metrics based on comparisons of MeHg exposure to the 
reference dose. We are focusing on exposures above the RfD because it 
represents a sensitive risk metric that captures a wide range of 
neurobehavioral health effects. Reductions in exposure to MeHg are also 
expected to result in reductions in specific adverse effects including 
lost IQ points, and we discuss the risk analysis related to IQ loss in 
the National Scale Mercury Risk Assessment TSD.
    For the analysis, we have developed a risk characterization 
framework for integrating two types of U.S. EGU-attributable risk 
estimates. This framework estimates the percent of watersheds where 
populations may be at risk due to potential exposures to MeHg 
attributable to U.S. EGU. The analysis is limited to those watersheds 
for which we have fish tissue MeHg samples, a total of approximately 
2,400 out of 88,000 watersheds in the U.S. This total percent of 
watersheds includes ones that either have deposition of Hg from U.S. 
EGUs that is sufficient to lead to potential exposures that exceed the 
reference dose, even without considering the contributions from other 
U.S. and non-U.S. sources, or have deposition of Hg from U.S. EGUs that 
contributes at least 5 percent to total Hg deposition from all sources, 
in watersheds where potential exposures to MeHg from all sources (U.S. 
EGU, U.S. non-EGU, and non-U.S.) exceed the RfD.
    This framework allows EPA to consider whether U.S. EGUs, evaluated 
without consideration of other sources, or in combination with other 
sources of Hg, pose a potential public health hazard.
iii. Analytical Approach
    Several elements of this risk analysis including spatial scale, 
estimates of Hg deposition, estimates of fish tissue MeHg 
concentrations, estimates of fish consumptions rates, and calculation 
of

[[Page 25008]]

MeHg exposure are discussed in detail in the National Scale Mercury 
Risk Assessment TSD accompanying this finding, and are briefly 
summarized below.
    Watersheds can be defined at varying levels of spatial resolution. 
For the purposes of this risk analysis, we have selected to use 
watersheds classified using 12-digit Hydrologic Unit Codes (HUC12),\95\ 
representing a fairly refined level of spatial resolution with 
watersheds generally 5 to 10 km on a side, which is consistent with 
research on the relationship between changes in Hg deposition and 
changes in MeHg levels in aquatic biota.
---------------------------------------------------------------------------

    \95\ U.S. Geological Survey and U.S. Department of Agriculture, 
Natural Resources Conservation Service, 2009, Federal guidelines, 
requirements, and procedures for the national Watershed Boundary 
Dataset: U.S. Geological Survey Techniques and Methods 11-A3, 55 p.
---------------------------------------------------------------------------

    After estimating total MeHg risk based on modeling consumption of 
fish at each of these watersheds, the ratio of U.S. EGU to total Hg 
deposition over each watershed (estimated using Community Multi-scale 
Air Quality modeling) is used to estimate the U.S. EGU-attributable 
fraction of total MeHg risk. This apportionment of total risk between 
the U.S. EGU fraction and the fraction associated with all other 
sources of Hg deposition is based on the EPA's Office of Water's 
Mercury Maps (MMaps) approach that establishes a proportional 
relationship between Hg deposition over a watershed and resulting fish 
tissue Hg levels, assuming a number of criteria are met.\96\
---------------------------------------------------------------------------

    \96\ Mercury Maps--A Quantitative Spatial Link Between Air 
Deposition and Fish Tissue Peer Reviewed Final Report. U.S. EPA, 
Office of Water, EPA-823-R-01-009, September, 2001.
---------------------------------------------------------------------------

    The fish tissue dataset for the risk assessment includes fish 
tissue Hg samples from the years 2000 to 2009, with samples distributed 
across 2,461 HUC12s. The samples are more heavily focused on locations 
east of the Mississippi River. The fish tissue samples come primarily 
from three sources: the National Listing of Fish Advisory (NLFA) 
database managed by EPA; \97\ the U.S. Geologic Survey (USGS), which 
manages a compilation of Hg datasets as part of its Environmental 
Mercury Mapping and Analysis (EMMA) program, and EPA's National River 
and Stream Assessment (NRSA) study data. Most of the watersheds with 
measured fish tissue MeHg data had multiple measurements. This 
assessment used the 75th percentile fish tissue value at each watershed 
as the basis for exposure and risk characterization, based on the 
assumption that subsistence fishers would favor larger fish which have 
the potential for higher bioaccumulation. The use of the 75th 
percentile fish tissue MeHg value as the basis for risk 
characterization reflects our overall goal of modeling realistic high-
end fishing behavior; in this case, reflecting individuals who target 
somewhat larger fish for purposes of supplementing their diets (the 
average fisher may eat a variety of different sized fish, but in order 
to capture higher potential MeHg exposure scenarios, it is realistic to 
assume that some fishers may favor somewhat larger fish).
---------------------------------------------------------------------------

    \97\ http://water.epa.gov/scitech/swguidance/fishshellfish/fishadvisories/.
---------------------------------------------------------------------------

    Deposition of Hg for the continental U.S. was estimated using the 
Community Multiscale Air Quality model v4.7.1 (http://www.cmaq-model.org), applied at a 12 km grid resolution.
    The CMAQ modeling was used to estimate total annual Hg deposition 
from U.S. and non-U.S. anthropogenic and natural sources over each 
watershed. In addition, CMAQ simulations were conducted where U.S. EGU 
Hg emissions were set to zero to determine the contribution of U.S. EGU 
Hg emissions to total Hg deposition. U.S. EGU-related Hg deposition 
characterized at the watershed-level for 2005 and 2016 is summarized in 
Table 6 of this preamble for the complete set of 88,000 HUC12 
watersheds.
    Table 6 is intended to demonstrate the wide variation across 
watersheds in the contribution of EGU emissions to deposition. The 
percentiles of total Hg deposition and U.S. EGU-attributable deposition 
are not linked, e.g., the 99th percentile of the percent of total 
deposition attributable to U.S. EGUs is based on the distribution of 
total Hg deposition, and the 99th percentile of U.S. EGU-attributable 
Hg deposition is based on the distribution of U.S. EGU-attributable 
deposition. These percentiles do not occur at the same watershed.

   Table 6--Comparison of Total and U.S. EGU-Attributable Hg Deposition ([micro]g/m\2\) for the 2005 and 2016
                                                   Scenarios *
----------------------------------------------------------------------------------------------------------------
                                                                       2005                       2016
                                                           -----------------------------------------------------
                                                                           U.S. EGU-                  U.S. EGU-
                         Statistic                            Total Hg   attributable    Total Hg   attributable
                                                             deposition       Hg        deposition       Hg
                                                                          deposition                 deposition
----------------------------------------------------------------------------------------------------------------
Mean......................................................        19.41          0.89        18.66          0.34
Median....................................................        17.25          0.24        16.59          0.15
75th percentile...........................................        23.69          1.07        22.83          0.46
90th percentile...........................................        30.78          2.38        29.90          0.85
95th percentile...........................................        36.85          3.60        35.16          1.18
99th percentile...........................................        58.32          7.77        56.23          2.41
----------------------------------------------------------------------------------------------------------------
* Statistics are based on CMAQ results interpolated to the watershed-level and are calculated using all ~88,000
  watersheds in the U.S.

    To give a better idea of the relationship between total deposition 
and U.S. EGU-attributable deposition, we also summarize the percent of 
total Hg deposition attributable to U.S. EGUs (by percentile) in Table 
7. Table 7 shows the high variability in the percent contribution from 
U.S. EGU Hg emissions. Tables 6 and 7 cannot be directly compared, as 
the watershed with the 99th percentile U.S. EGU-attributable deposition 
is not the same watershed as the watershed with the 99th percentile 
U.S. EGU-attributable fraction of total Hg deposition. A watershed can 
have a high U.S. EGU-attributable fraction of total deposition and 
still have overall low Hg deposition.

[[Page 25009]]



  Table 7--Comparison of Percent of Total Hg Deposition Attributable to
                      U.S. EGUs for 2005 and 2016 *
------------------------------------------------------------------------
                                         2005         2016
             Statistic                (percent)    (percent)
-------------------------------------------------------------
Mean...............................            5            2
Median.............................            1            1
75th percentile....................            6            3
90th percentile....................           13            5
95th percentile....................           18            6
99th percentile....................           30           11
------------------------------------------------------------------------
* Values are based on CMAQ results interpolated to the watershed-level
  and reflect trends across all ~88,000 watersheds in the U.S.

    U.S. EGUs are estimated to contribute up to 30 percent of total Hg 
deposition in 2005 and up to 11 percent in 2016.
    EPA estimates the relationship between the EGU-attributable Hg 
deposition and EGU-attributable fish tissue MeHg concentrations using 
an assumption of linear proportionality based on the agency's MMaps 
approach. The MMaps assumption specifies that, under certain conditions 
(e.g., Hg air deposition is the primary source of Hg loading to a 
watershed and near steady-state conditions have been reached), a 
fractional change in Hg deposition to a watershed will ultimately be 
reflected in a matching proportional change in the levels of MeHg in 
fish.98 99 This assumption holds in watersheds where air 
deposition is the primary source of Hg loadings, and as a result, 
watersheds where this is not the case are removed from the risk 
analysis. The practical application of the MMaps approach is that U.S. 
EGUs will account for the same proportion of fish tissue MeHg in a 
watershed as they do for Hg deposition. MMaps is discussed in greater 
detail in section 1.3 and Appendix E of the National Scale Mercury Risk 
Assessment TSD. Patterns of U.S. EGU-attributable fish tissue MeHg 
concentrations are summarized in Table 8 of this preamble. Table 8 of 
this preamble compares total and U.S. EGU-attributable fish tissue MeHg 
concentrations for the 2005 and 2016 scenarios by watershed percentile.
---------------------------------------------------------------------------

    \98\ The MMaps approach implements a simplified form of the IEM-
2M model applied in EPA's Mercury Study Report to Congress (Mercury 
Maps--A Quantitative Spatial Link Between Air Deposition and Fish 
Tissue Peer Reviewed Final Report. U.S. EPA, Office of Water, EPA-
823-R-01-009, September, 2001). By simplifying the assumptions 
inherent in the freshwater ecosystem models that were described in 
the Report to Congress, the MMaps model showed that these models 
converge at a steady-state solution for MeHg concentrations in fish 
that are proportional to changes in Hg inputs from atmospheric 
deposition (e.g., over the long term fish concentrations are 
expected to decline proportionally to declines in atmospheric 
loading to a watershed). This solution only applies to situations 
where air deposition is the only significant source of Hg to a water 
body, and the physical, chemical, and biological characteristics of 
the ecosystem remain constant over time. EPA recognizes that 
concentrations of MeHg in fish across all ecosystems may not reach 
steady state and that ecosystem conditions affecting Hg dynamics are 
unlikely to remain constant over time. EPA further recognizes that 
many water bodies, particularly in areas of historic gold and Hg 
mining in western states, contain significant non-air sources of Hg 
(note, however, that as described below, we have excluded those 
watersheds containing gold mines or with other non-EGU related 
anthropogenic Hg releases exceeding specified thresholds).
    \99\ The risk assessment is not designed to track the detailed 
temporal profile associated with changes in fish tissue MeHg levels 
following changes in Hg deposition. Rather, we are focusing on 
estimating risk in the future, assuming that near steady state 
conditions have been reached (following a simulated change in Hg 
deposition). Additional detail regarding the temporal profile issue 
and other related factors (e.g., methylation potential across 
watersheds) is discussed in Section 1.3 and in Appendix E of the 
National Scale Mercury Risk Assessment TSD).

    Table 8--Comparison of Total and U.S. EGU-Attributable Fish Tissue MeHg Concentrations for 2005 and 2016
----------------------------------------------------------------------------------------------------------------
                                                                    Fish tissue MeHg concentration (ppm)
                                                           -----------------------------------------------------
                                                                       2005                       2016
                         Statistic                         -----------------------------------------------------
                                                                           U.S. EGU-                  U.S. EGU-
                                                               Total     attributable     Total     attributable
----------------------------------------------------------------------------------------------------------------
Mean......................................................         0.31         0.024         0.29         0.008
50th Percentile...........................................         0.23         0.014         0.20         0.005
75th Percentile...........................................         0.39         0.032         0.36         0.011
90th Percentile...........................................         0.67         0.056         0.63         0.019
95th Percentile...........................................         0.91         0.079         0.87         0.026
99th Percentile...........................................         1.34         0.150         1.29         0.047
----------------------------------------------------------------------------------------------------------------

    Because the focus of this analysis is on higher-consumption self-
caught fisher populations active at inland freshwater locations, we 
identified surveys of higher consumption fishing populations active at 
inland freshwater rivers and lakes within the continental U.S. to 
inform the selection of consumption rate scenarios.\100\

[[Page 25010]]

Information on the studies used to develop the high end fish 
consumption scenarios for the risk analysis is provided in the National 
Scale Mercury Risk Assessment TSD.
---------------------------------------------------------------------------

    \100\ A number of criteria had to be met for a study to be used 
in providing explicit consumption rates for the high-end fisher 
populations of interest in this analysis. For example, studies had 
to provide estimates of self-caught fish consumption and not 
conflate these estimates with consumption of commercially purchased 
fish. Furthermore, these studies had to focus on freshwater fishing 
activity, or at least have the potential to reflect significant 
contributions from that category, such that the fish consumption 
rates provided in a study could be reasonably applied in assessing 
freshwater fishing activity. Studies also had to provide statistical 
estimates of fish consumptions (i.e., means, medians, 90th 
percentiles, etc). Given our interest in higher-end consumption 
rates, the studies also had to either provide upper percentile 
estimates, or support the derivation of those estimates (e.g., 
provide medians and a standard deviations). Studies of activity at 
specific watersheds (e.g., creel surveys), while informative in 
supporting the presence of higher-end consumption rates, could not 
be used as the basis for defining our high-end consumption rates 
since there would be greater uncertainty in extrapolating activity 
at a specific river or lake more broadly to fishing populations in a 
region. Therefore, we focused on studies characterizing fishing 
activity more broadly than at a specific fishing location.
---------------------------------------------------------------------------

    Generally all of the studies identified high-end percentile 
consumption rates (90th to 99th percentiles for the populations 
surveyed) ranging from approximately one fish meal every few days to a 
fish meal a day (i.e., 120 grams per day (g/day) to greater than 500 g/
day fish consumption). We used this trend across the studies to support 
application of a generalized female high-end fish consumption scenario 
(high-end female consumer scenario) across most of the 2,461 
watersheds.\101\
---------------------------------------------------------------------------

    \101\ Reflecting the fact that higher levels of self-caught fish 
consumption (approaching subsistence) have been associated with 
poorer populations, we only assessed this generalized high-end 
female consumer scenario at those watersheds located in U.S. Census 
tracts with at least 25 individuals living below the poverty line 
(this included the vast majority of the 2,461 watersheds and only a 
handful were excluded due to this criterion).
---------------------------------------------------------------------------

iv. Risk Related to Exposure to MeHg in Fish and Assessment of 
Contribution of U.S. EGUs to MeHg Exposure and Risk
    For the scenario representing high-end female fish consumption, we 
estimated total exposure to MeHg at each of the 2,461 watersheds.\102\ 
Estimates of total Hg exposure were generated by combining 75th 
percentile fish tissue values with the consumption rates for female 
subsistence fishers. A cooking loss factor (reflecting the fact that 
the preparation of fish can result in increased Hg concentrations) was 
also included in exposure calculations.\103\
---------------------------------------------------------------------------

    \102\ As noted earlier, each high-end fish consuming female 
population included in the analysis was assessed for a subset of 
these watersheds, depending on which of those watersheds intersected 
a U.S. Census tract containing a ``source population'' for that fish 
consuming population. Of the populations assessed, the low-income 
female subsistence fishing population scenario was assessed for the 
largest portion (2,366) of the 2,461 watersheds.
    \103\ 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.
---------------------------------------------------------------------------

    Our estimates of total percent of watersheds where female 
subsistence fishing populations may be at risk from exposure to U.S. 
EGU-attributable MeHg are as high as 28 percent. The upper end estimate 
of 28 percent of watersheds reflects the 99th percentile fish 
consumption rate for that population, and a benchmark of 5 percent U.S. 
EGU contribution to total Hg deposition in the watershed. Any 
contribution of Hg emissions from EGUs to watersheds where potential 
exposures from total Hg deposition exceed the RfD is a hazard to public 
health, but for purposes of our analyses we evaluated only those 
watersheds where we determined EGUs contributed 5 percent or more to 
deposition to the watershed. EPA believes this is a conservative 
approach given the increasing risks associated with incremental 
exposures above the RfD. Of the total number of watersheds where 
populations may be at risk from exposure to EGU-attributable MeHg, we 
estimate that up to 22 percent of watersheds included in this analysis 
could potentially have populations at risk based on consideration of 
the U.S. EGU attributable fraction (e.g., 5, 10, 15, or 20 percent) of 
total Hg deposition over watersheds with total risk judged to represent 
a public health hazard (MeHg total exposure greater than the RfD).\104\ 
Of the total number of watersheds where populations may be at risk from 
exposures to U.S. EGU-attributable MeHg, we estimate that up to 12 
percent of watersheds included in this analysis could potentially have 
populations at risk because the U.S. EGU incremental contribution to 
exposure is above the RfD, even before consideration of contributions 
to exposures from U.S. non-EGU and non-U.S. sources. In other words, 
for this 12 percent of watersheds, even if there were no other sources 
of Hg exposure, exposures associated with deposition attributable to 
U.S. EGUs would place female high-end consumers above the MeHg RfD. The 
upper end estimate of 12 percent of watersheds reflects a scenario 
using the 99th percentile fish consumption rate.
---------------------------------------------------------------------------

    \104\ Because of the MMaps assumption of linear proportionality 
between deposition and exposures, a 5 percent U.S. EGU contribution 
to deposition will produce an equivalent 5 percent U.S. EGU 
contribution to MeHg exposures.
---------------------------------------------------------------------------

    The two estimates of percent of watersheds where populations may be 
at risk from EGU-attributable Hg do not sum to the total estimates of 
28 percent because some watersheds where U.S. EGUs contribute greater 
than 5 percent to total Hg deposition also have U.S. EGU attributable 
exposures that exceed the RfD without consideration of exposures from 
other U.S. and non-U.S. Hg sources.
    Exposures based on the 99th percentile consumption rate represent 
close to maximum potential individual risk estimates. These consumption 
rates are based on data reported by fishers in surveys, and, thus, 
represent actual consumption rates in U.S. populations. There are also 
a number of case studies in other locations, such as poor urban areas, 
which provide additional evidence that high fish consumption occurs in 
a number of locations throughout the U.S.105 106 107 108 
However, EPA does not have sufficiently complete data on the specific 
locations where these high self-caught fish consuming populations 
reside and fish, and as a result, there is increased uncertainty about 
the prevalence of populations who are high-end consumers of fish caught 
in the set of watersheds included in the analysis. Populations matching 
the high-end fish consumption scenario could be restricted to a subset 
of these watersheds, or could be more heavily focused at watersheds 
with higher or lower U.S. EGU-attributable fish tissue MeHg (and 
consequently higher or lower U.S. EGU-attributable risk).
---------------------------------------------------------------------------

    \105\ Burger, J., K. Pflugh, L. Lurig, L. Von Hagen, and S. Von 
Hagen. 1999. Fishing in Urban New Jersey: Ethnicity Affects 
Information Sources, Perception, and Compliance. Risk Analysis 
19(2): 217-229.
    \106\ Burger, J., Stephens, W., Boring, C., Kuklinski, M., 
Gibbons, W.J., & Gochfield, M. (1999). Factors in exposure 
assessment: Ethnic and socioeconomic differences in fishing and 
consumption of fish caught along the Savannah River. Risk Analysis, 
19(3).
    \107\ 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, California Environmental 
Protection Agency, July 1997.
    \108\ 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).
---------------------------------------------------------------------------

    With regard to the other fisher populations included in the full 
risk assessment described in the TSD (Vietnamese, Laotians, Hispanics, 
blacks and whites in the southeast, and tribes in the vicinity of the 
Great Lakes), our risk estimates suggests that the high-end female 
consumer assessed at the national-level generally provides coverage (in 
terms of magnitude of risk) for all of these fisher populations except 
blacks and whites in the southeast.109 110
---------------------------------------------------------------------------

    \109\ Specifically, upper percentile risk estimates for the 
high-end female consumer assessed at the national level were notably 
higher than matching percentile estimates for the Hmong, Vietnamese, 
Hispanic, and Tribal populations. By contrast, risk estimates for 
whites in the southeast were somewhat higher than the high-end 
female consumer, while risk estimates for blacks in the southeast 
were notably higher (see summary of risk estimates in the TSD 
supporting this finding).
    \110\ The National Scale Mercury Risk Assessment TSD discusses 
the greater uncertainty in characterizing the magnitude of high-end 
fish consumption for these specialized populations due, in 
particular, to the lower sample sizes associated with the survey 
data (see Appendix C, Table C-1).

---------------------------------------------------------------------------

[[Page 25011]]

v. Variability and Uncertainty (Including Discussion of Sensitivity 
Analyses)
    There are some uncertainties in EPA's analyses which could lead to 
under or over prediction of risk to public health from U.S. EGU Hg 
emissions. Based on sensitivity analyses we have conducted, we conclude 
that even under different assumptions about the applicability of the 
MMaps proportionality assumption, Hg from U.S. EGUs constitutes a 
hazard to public health due to the percent of watersheds where U.S. 
EGUs cause or contribute to exposures to MeHg above the RfD.
    Key sources of uncertainty potentially impacting the risk analysis 
include: (1) Uncertainty in predicting Hg deposition over watersheds 
using CMAQ; (2) uncertainty in predicting which watersheds will be 
subject to high-end fishing activity and the nature of that activity 
(e.g., frequency of repeated activity at a given watershed and the 
types/sizes of fish caught); (3) uncertainty in using MMaps to 
apportion exposure and risk between different sources, including U.S. 
EGUs, and predicting changes in fish tissue MeHg levels for future 
scenarios; and (4) potential under-representation of watersheds highly 
impacted by U.S.-attributable Hg deposition due to limited MeHg 
sampling. In the National Scale Mercury Risk Assessment TSD, we 
describe in greater detail key sources of uncertainty impacting the 
risk analysis, including their potential impact on the risk estimates 
and the degree to which their potential impact is characterized as part 
of the analysis.
    As part of the analysis, we have also completed a number of 
sensitivity analyses focused on exploring the impact of uncertainty 
related to the application of the MMaps approach in apportioning 
exposure and risk estimates between sources (U.S. EGU and total) and in 
predicting changes in fish tissue MeHg levels.\111\ These sensitivity 
analyses evaluated: (1) The effect of including watersheds that may be 
disproportionately impacted by non-air Hg sources; \112\ and (2) the 
representativeness of the MMaps approach, which was tested for lakes, 
when applied to streams and rivers (in the analysis, the MMaps was 
applied to watersheds including a mixture of streams, rivers, and 
lakes). The results of the limited sensitivity analyses we were able to 
conduct suggest that uncertainties due to application of MMaps would 
not affect our finding that U.S. EGU-attributable Hg deposition poses a 
hazard to public health.
---------------------------------------------------------------------------

    \111\ The sensitivity analyses completed for the risk assessment 
focused on assessing sources of uncertainty associated with the 
application of the MMaps approach, because this was a critical 
element in the risk assessment and identified early on as a key 
source of potential uncertainty. Given the schedule of the analysis, 
we did not have time to complete a full influence analysis to 
identify those additional modeling elements that might introduce 
significant uncertainty and therefore should be included in a 
sensitivity analysis. Appendix F, Table F-2 of the Mercury Risk TSD 
provides a qualitative discussion of key sources of uncertainty and 
their potential impact on the risk assessment.
    \112\ In addition to non-air Hg sources of loadings, some 
regions of concern may also have longer lag period associated with 
the linkage between Hg deposition such that the fish tissue MeHg 
levels we are using are actually associated with older historical Hg 
deposition patterns.
---------------------------------------------------------------------------

    We also examined the potential for under-representation of 
watersheds highly impacted by U.S.-attributable Hg deposition due to 
limited MeHg sampling, by identifying watersheds that did not have fish 
tissue MeHg samples, but had U.S. EGU-attributable Hg deposition at 
least as high as watersheds that were identified as being at risk of 
potential exposures greater than the RfD. Comparing the pattern of U.S. 
EGU-attributable Hg deposition across all watersheds with that for 
watersheds containing fish tissue MeHg data shows that while we have 
some degree of coverage for watersheds with high U.S. EGU-attributable 
deposition, this coverage is limited, especially in areas of 
Pennsylvania which have high levels of U.S. EGU-attributable 
deposition. For this reason, we believe that the actual number of 
watersheds where populations may be at risk from exposures to U.S. EGU-
attributable MeHg could be substantially larger than the number 
estimated based on the available fish tissue MeHg sampling data.
d. U.S. EGU Case Studies of Cancer and Non-Cancer Inhalation Risks for 
Non-Hg HAP
    EPA conducted 16 case studies to estimate the potential for human 
health impacts from current emissions of HAP other than Hg from EGUs. A 
refined chronic inhalation risk assessment was performed for each case 
study facility. The results of this analysis were that 4 (out of 16) 
facilities posed a lifetime cancer risk of greater than 1 in 1 million 
(the maximum was 10 in 1 million) and 3 more posed a risk at 1 in 1 
million. Risk was driven by Ni (the oil-fired unit) and Cr+6 
(the coal-fired units).
i. Case Study Selection
    An initial set of eight case study facilities was selected based on 
several factors. First, we considered facilities with the highest 
estimated cancer and non-cancer risks using the 2005 National Emissions 
Inventory (NEI) data and the Human Exposure Model (HEM). The 2005 NEI 
data were used because the initial set of case study facilities was 
selected before we received the bulk of the emissions data from the 
2010 ICR. Other factors considered in the selection included whether 
facilities had implemented emission control measures since 2005, and 
their proximity to residential areas. After the receipt of more data 
through the 2010 ICR, additional case study facilities were selected, 
based on the magnitude of emissions, heat input values (throughput), 
and level of emission control. There were a total of 16 case study 
facilities, 15 that use coal as fuel, and 1 that uses oil.
ii. Methods
    Annual emissions estimates for each EGU (including those in the 
initial set of case study facilities) were developed using data from 
the 2010 ICR. The results for the initial set indicated that Ni, 
Cr+6, and As were the cancer risk drivers, and that non-
cancer risks did not produce any hazard index (HI) estimates exceeding 
one. Although the non-cancer risks were low (the maximum chronic 
noncancer HI was 0.4), they were driven by emissions of Ni, As, and 
HCl. For the reasons discussed above, emissions were estimated only for 
Ni, Cr+6, and As for the additional case study facilities. 
Additional details on the emissions used in the modeling are provided 
in a supporting memorandum to the docket for this action (Non-Hg Case 
Study Chronic Inhalation Risk Assessment for the Utility MACT 
``Appropriate and Necessary'' Analysis) (Non-Hg Memo). For each of the 
16 case study facilities, we conducted refined dispersion modeling with 
EPA's AERMOD modeling system (U.S. EPA, 2004) to calculate annual 
ambient concentrations. Average annual concentrations were calculated 
at census block centroids.
    We calculated the MIR for each facility as the cancer risk 
associated with a continuous lifetime (24 hours per day, 7 days per 
week, and 52 weeks per year for a 70-year period) exposure to the 
maximum concentration at the centroid of an inhabited census block, 
based on application of the unit risk estimate from EPA's IRIS, which 
is a human health assessment program that evaluates quantitative and 
qualitative risk information on effects that may result from exposure 
to environmental contaminants. For Ni compounds, we

[[Page 25012]]

used 65 percent of the IRIS URE for nickel subsulfide. The 
determination of this value is discussed in the Non-Hg Memo, and the 
value is receiving peer review as discussed in section later. To assess 
the risk of non-cancer health effects from chronic exposures, following 
the approach recommended in EPA's Mixtures 
Guidelines,113 114 we summed the HQs for all HAP that affect 
a common target organ system to obtain the HI for that target organ 
system (target-organ-specific HI, or TOSHI). The HQ for chronic 
exposures is the estimated chronic exposure (again, based on the 
estimated annual average ambient concentration at each nearby census 
block centroid) divided by the chronic non-cancer reference level, 
which is usually the EPA reference concentration (RfC). In cases where 
an IRIS RfC is not available, EPA utilizes the following prioritized 
sources for chronic dose-response values: (1) The Agency for Toxic 
Substances and Disease Registry (ATSDR) Minimum Risk Level (MRL), and 
(2) the California Environmental Protection Agency chronic Reference 
Exposure Level (REL). In this assessment, we used the IRIS RfC values 
for Cr+6 and HCl, the ATSDR MRL for Ni compounds, and the 
California Environmental Protection Agency REL for As.
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    \113\ U.S. EPA, 1986, Guidelines for the Health Risk Assessment 
of Chemical Mixtures, EPA-630-R-98-002. http://www.epa.gov/NCEA/raf/pdfs/chem_mix/chemmix_1986.pdf.
    \114\ U.S. EPA, 2000. Supplementary Guidance for Conducting 
Health Risk Assessment of Chemical Mixtures. EPA-630/R-00-002. 
http://www.epa.gov/ncea/raf/pdfs/chem_mix/chem_mix_08_2001.pdf.
---------------------------------------------------------------------------

iii. Results
    The highest estimated lifetime cancer risk from any of the 16 case 
study facilities was 10 in 1 million (1 x 10-5), driven by 
Ni emissions from the 1 case study facility with oil-fired units. For 
the facilities with coal-fired units, there were 3 with maximum cancer 
risks greater than 1 in 1 million (the highest was 8 in 1 million), all 
driven by Cr+6, and there were 4 with maximum cancer risks 
at 1 in 1 million. All of the facilities had non-cancer TOSHI values 
less than one, with a maximum HI value of 0.4 (also driven by Ni 
emissions from the one case study facility with oil-fired units). The 
maximum chronic impacts of HCl emissions were all less than 10 percent 
of its chronic RfC. Because of uncertainties in their emission rates, 
other acid gases (Cl2, HF, and HCN) were not included in the 
assessment of noncancer impacts. Because EGUs are not generally co-
located with other source categories, facility-wide HAP emissions and 
risks are equal to those associated with the EGU source category.
    The cancer risk estimates from this assessment indicate that the 
EGU source category is not eligible for delisting under CAA section 
112(c)(9)(B)(i), which specifies that a category may be delisted only 
when the Administrator determines ``* * * that no source in the 
category (or group of sources in the case of area sources) emits such 
HAP 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 * * *'' We note 
that, because these case studies do not cover all facilities in the 
category, and because 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 may underestimate true maximum 
risks.
e. Peer-Review of Quantitative Risk Analyses
    The Agency has determined that the National-Scale Mercury Risk 
Analysis supporting EPA's 2011 review of U.S. EGU health impacts should 
be peer-reviewed. In addition, the Agency has determined that the 
characterization of the chemical speciation for the emissions of Cr and 
Ni should be peer-reviewed. The Agency has evaluated the other 
components of the analyses supporting this finding and determined that 
the remaining aspects of the case study analyses for non-Hg HAP use 
methods that have already been subject to adequate peer-review. As a 
result, the Agency is limiting the peer-review to the National-Scale 
Mercury Risk Analysis and the speciation of emissions for Cr and Ni. 
Due to the court-ordered schedule for this proposed rule, EPA will 
conduct these peer reviews as expeditiously as possible after issuance 
of this proposed rule and will publish the results of the peer reviews 
and any EPA response to them before the final rule.
4. Qualitative Assessment of Potential Environmental Risks From 
Exposures of Ecosystems Through Hg and Non-Hg HAP Deposition
    Adverse effects on fish and wildlife have been observed to be 
occurring today which are the result of elevated exposures to MeHg, 
although these effects have not been quantitatively assessed.
    Elevated MeHg concentrations in fish and wildlife can occur not 
only in areas of high Hg deposition. Elevated MeHg concentrations can 
also occur in diverse locations, including watersheds that receive 
average or even relatively low Hg deposition, but are particularly 
sensitive to Hg pollution, for example, they have higher than average 
methylation rates due to high levels of sulfur deposition. Such 
locations are characterized by moderate deposition levels that have 
generated high Hg concentrations in biota compared to the surrounding 
landscape receiving a similar Hg loading. These Hg-sensitive watersheds 
readily transport inorganic Hg, convert the inorganic Hg to MeHg, and 
bioaccumulate this MeHg through the food web. Areas of enhanced MeHg in 
fish and wildlife are not constrained to a single Hg source, because 
ecosystems respond to the combined effects of Hg pollution from 
multiple sources.
    A review of the literature on effects of Hg on reproduction in 
fish\115\ reports adverse reproductive effects for numerous species 
including trout, bass (large and smallmouth), northern pike, carp, 
walleye, salmon, and others from laboratory and field studies. Mercury 
also affects avian species. In previous reports \116\ much of the focus 
has been on large fish-eating species, in particular the common loon. 
Breeding loons experience significant adverse effects including 
behavioral (reduced nest-sitting), physiological (flight feather 
asymmetry) and reproductive (chicks fledged/territorial pair) 
effects.\117\
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    \115\ Crump, Kate L., and Trudeau, Vance L. Mercury-induced 
reproductive impairment in fish. Environmental Toxicology and 
Chemistry. Vol. 28, No. 5, 2009.
    \116\ 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. 
Office of Air Quality Planning and Standards, 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.
    \117\ Evers, David C., Savoy, Lucas J., DeSorbo, Christopher R., 
Yates, David E., Hanson, William, Taylor, Kate M., Siegel, Lori S., 
Cooley, John H. Jr., Bank, Michael S., Major, Andrew, Munney, 
Kenneth, Mower, Barry F., Vogel, Harry S., Schoch, Nina, Pokras, 
Mark, Goodale, Morgan W., Fair, Jeff. Adverse effects from 
environmental mercury loads on breeding common loons. Ecotoxicology. 
17:69-81, 2008.
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    Other fish-eating bird species such as the white ibis and great 
snowy egret experience a range of adverse effects due to exposure to 
Hg. The white ibis has been observed to have decreased foraging 
efficiency \118\ and decreased

[[Page 25013]]

reproductive success and altered pair behavior.\119\ These effects 
include significantly more unproductive nests, male/male pairing, 
reduced courtship behavior and lower nestling production by exposed 
males. In egrets, Hg has been implicated in the decline of the species 
in south Florida \120\ and studies show liver and possibly kidney 
effects.\121\ 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,\122\ lower survival,\123\ and had 
compromised immune competence.\124\ The great tit has exhibited reduced 
singing behavior and smaller song repertoire in areas of high 
contamination.\125\
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    \118\ Adams, Evan M., and Frederick, Peter C. 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.
    \119\ Frederick, Peter, and Jayasena, Nilmini. 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.
    \120\ Sepulveda, Maria S., Frederick, Peter C., Spalding, 
Marilyn G., and Williams, Gary E. Jr. Mercury contamination in free-
ranging great egret nestlings (Ardea albus) from southern Florida, 
USA. Environmental Toxicology and Chemistry. Vol. 18, No.5, 1999.
    \121\ Hoffman, David J., Henny, Charles J., Hill, Elwood F., 
Grover, Robert A., Kaiser, James L., Stebbins, Katherine R. 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.
    \122\ Brasso, Rebecka L., and Cristol, Daniel A. Effects of 
mercury exposure in the reproductive success of tree swallows 
(Tachycineta bicolor). Ecotoxicology. 17:133-141, 2008.
    \123\ Hallinger, Kelly K., Cornell, Kerri L., Brasso, Rebecka 
L., and Cristol, Daniel A. Mercury exposure and survival in free-
living tree swallows (Tachycineta bicolor). Ecotoxicology. Doi: 
10.1007/s10646-010-0554-4, 2010.
    \124\ Hawley, Dana M., Hallinger, Kelly K., Cristol, Daniel A. 
Compromised immune competence in free-living tree swallows exposed 
to mercury. Ecotoxicology. 18:499-503, 2009.
    \125\ Gorissen, Leen, Snoeijs, Tinne, Van Duyse, Els, and Eens, 
Marcel. Heavy metal pollution affects dawn singing behavior in a 
small passerine bird. Oecologia. 145:540-509, 2005.
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    In mammals, adverse effects from Hg including mortality have been 
observed in mink and river otter, both fish eating species. Other 
adverse effects may include increased activity, poorer maze 
performance, abnormal startle reflex, and impaired escape and avoidance 
behavior.\126\ EPA is also concerned about the potential impacts of HCl 
and other acid gas emissions on the environment. When HCl gas 
encounters water in the atmosphere, it forms an acidic solution of 
hydrochloric acid. In areas where the deposition of acids derived from 
emissions of sulfur and NOX are causing aquatic and/or 
terrestrial acidification, with accompanying ecological impacts, the 
deposition of hydrochloric acid would further exacerbate these impacts. 
Recent research\127\ has, in fact, determined that deposition of 
airborne HCl has had a greater impact on ecosystem acidification than 
anyone had previously thought, although direct quantification of these 
impacts remains an uncertain process.
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    \126\ Scheuhammer, Anton M., Meyer Michael W., Sandheinrich, 
Mark B., and Murray, Michael W. Effects of environmental 
methylmercury on the health of wild birds, mammals, and fish. Ambio. 
Vol.36, No.1, 2007.
    \127\ Evans, Chris D., Monteith, Don, T., Fowler, David, Cape, 
J. Neil, and Brayshaw, Susan. Hydrochloric Acid: An Overlooked 
Driver of Environmental Change, Env. Sci. Technol., DOI: 10.1021/
es10357u.
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5. Potential for Deposition ``Hotspots'' in Areas Near U.S. EGUs
    Although it has been characterized and addressed as a global issue, 
Hg from U.S. EGUs is shown to deposit in higher quantities close to 
emission sources, and around some sources can be as high as 3 times the 
regional average deposition. EPA evaluated the potential for ``hot 
spot'' deposition near U.S. EGU emission sources on a national scale, 
based on the CMAQ modeled Hg deposition for 2005 and 2016.\128\ We 
calculated the excess deposition within 50 km of U.S. EGU sources by 
first calculating the average U.S. EGU attributable Hg deposition 
within a 500 km radius around the U.S. EGU source. This deposition 
represents the likely regional contribution around the EGU. We then 
calculated the average U.S. EGU attributable Hg deposition within 50 km 
of the U.S. EGUs to characterize local deposition plus regional 
deposition near the EGU facility. Excess local deposition is then the 
50 km radius average deposition minus the 500 km radius average 
deposition. Summary statistics for the excess local deposition are 
provided in Table 9 of this preamble. Table 9 of this preamble shows 
both the mean excess deposition around all U.S. EGUs, and the mean 
excess deposition around just the top 10 percent of Hg emitting U.S. 
EGUs. Table 9 of this preamble also shows the excess Hg deposition as a 
percent of the average regional deposition to provide context for the 
magnitude of the local excess deposition. In 2005, for all U.S. EGU, 
the excess was around 120 percent of the average deposition, while for 
the top 10 percent of Hg emitting U.S. EGU, local deposition was around 
3.5 times the regional average. By 2016, although the absolute excess 
deposition falls, the local excess still remains around 3 times the 
regional average for the highest 10 percent of Hg emitting U.S. EGUs.
---------------------------------------------------------------------------

    \128\ More details are provided in the National Scale Mercury 
Risk Assessment TSD.

  Table 9--Excess Local Deposition of Hg Based on 2005 CMAQ Modeled Hg
                               Deposition
------------------------------------------------------------------------
                                       50 km-Radius-average excess local
                                        deposition values ([mu]g/m\2\)
                                     -----------------------------------
                                         Mean across EGUs (percent of
                                         regional average deposition)
                                     -----------------------------------
                                            2005              2016
------------------------------------------------------------------------
All U.S. EGU sites with Hg emissions       1.65 (119%)        0.36 (93%)
 > 0 (672 sites)....................
Top ten percent U.S. EGU in Hg             4.89 (352%)       1.18 (302%)
 emissions (67 sites)...............
------------------------------------------------------------------------

    This analysis shows that there is excess deposition of Hg in the 
local areas around EGUs, especially those with high Hg emissions. 
Although this is not necessarily indicative of higher risk of adverse 
effects from consumption of MeHg contaminated fish from waterbodies 
around the U.S. EGUs, it does indicate an increased chance that Hg from 
U.S. EGUs will impact local waterbodies around the EGU sources, and not 
just impact regional deposition.
6. Emissions Controls for Emissions of Hg and Non-Hg HAP Are Available 
and Effective
    Analyses of currently available control technologies for Hg, acid 
gases,

[[Page 25014]]

and non-Hg metal HAP show that significant reductions in these 
pollutants can be achieved from EGUs with significant coincidental 
reductions in the emissions of other pollutants as well.
a. Availability of Hg Emissions Control Options
    The control of Hg in a coal combustion flue gas is highly dependent 
upon the form (or species) of the Hg. The Hg can be present in one of 
three forms: as Hg\0\, as a vapor of Hg+\2\ (e.g., mercuric 
chloride, Hg(Cl2)), or as HgP (e.g., adsorbed on 
fly ash or unburned carbon). The specific form of the Hg in the flue 
gas will strongly influence the effectiveness of available control 
technology for Hg control. The form (or ``speciation'') of the Hg is 
determined by the flue gas chemistry and by the time-temperature 
profile in the post combustion environment. During coal combustion, Hg 
is released into the exhaust gas as Hg\0\. This vapor may then continue 
through the flue gas cleaning equipment and exit the stack as gaseous 
Hg\0\ or it may be oxidized to Hg+\2\ compounds (such as 
HgCl2) via homogeneous (gas-gas) or heterogeneous (gas-
solid) reactions. The primary homogeneous oxidation mechanism is the 
reaction with gas-phase chlorine (Cl radical or possibly, HCl) to form 
HgCl2. Although this mechanism is thermodynamically 
favorable, it is thought to be kinetically limited due to rapid cooling 
of the flue gas stream. Heterogeneous oxidation reactions occur on the 
surface of fly ash and unburned carbon. It is thought that in-duct 
chlorination of the surface of the fly ash, unburned carbon, or 
injected activated carbon sorbent is the first step to heterogeneous 
oxidation and surface binding of vapor-phase Hg\0\ in the flue gas 
stream (i.e., the formation of HgP).
    Mercury control can occur as a ``co-benefit'' of conventional 
control technologies that have been installed for other purposes. 
Particulate Hg can be effectively removed along with other flue gas PM 
(including non-Hg metal HAP) in the primary or secondary PM control 
device. For units using electrostatic precipitators (ESPs), the 
effectiveness will depend upon the amount of HgP entering 
the ESP. Units that burn coals with higher levels of native chlorine 
and that produce more unburned carbon can see good Hg removal in the 
ESP. Fabric filters (FF) have been shown to provide very high levels of 
control when there is adequate halogen to convert the Hg to the 
oxidized form. Units with wet FGD scrubbers can achieve high levels of 
Hg control--provided that the Hg is present in the oxidized (i.e., the 
soluble) form. A selective catalytic reduction (SCR) catalyst can 
enhance the Hg removal by catalytically converting Hg\0\ to 
Hg+\2\, making it more soluble and more likely to be 
captured in the scrubber solution. Halogen additives (usually bromide 
salts, but chloride salts may also be used) can also be added directly 
to the coal or injected into the boiler to enhance the oxidation of Hg.
    Activated carbon injection (ACI) is the most successfully 
demonstrated Hg-specific control technology. In this case, a powdered 
AC sorbent is injected into the duct upstream of the primary or a 
secondary PM control device. The carbon is injected to maximize contact 
with the flue gas. Mercury binds on the surface of the carbon to form 
HgP, which is then removed in the PM control device. 
Conventional (i.e., non-halogenated) AC is effective when capturing Hg 
that is already predominantly in the oxidized state or when there is 
sufficient flue gas halogens to promote oxidation of the Hg on the AC 
surface. Pre-halogenated (i.e., brominated) AC has been shown to be 
very effective when used in combination with low chlorine coals (such 
as U.S. western subbituminous coals). Activated carbons can suffer from 
poor performance when used with high sulfur coals. 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 
AC (or unburned carbon) and limits the effectiveness of the injected 
AC. 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.
    Mingling of AC with the fly ash can affect the viability for use of 
the captured fly ash as an additive in concrete production. Use of the 
TOXECONTM configuration can keep the fly ash and the AC 
separate. This configuration consists of the primary PM control device 
(ESP or FF) followed by a secondary downstream pulsejet FF. The AC is 
injected prior to the secondary FF. The fly ash is captured in the 
primary PM control device and the AC and Hg are captured in the 
downstream secondary FF.
b. Availability of PM or Metal HAP Emissions Control Options
    Electrostatic precipitators and FFs are the most commonly applied 
PM control technologies in U.S. coal-fired EGUs. Newer units have 
tended to install FFs, which usually provide better performance than 
ESPs. An existing facility that wants to upgrade the PM control may 
choose to replace the current equipment with newer, better performing 
equipment. The facility may also consider installation of a downstream 
secondary PM control device--such as a secondary FF. A wet ESP (WESP) 
can be installed downstream of a wet FGD scrubber for control of 
condensable PM.
c. Availability of Acid Gas Emissions Control Options
    Acid gases are likely to be removed in typical FGD systems due to 
their solubility or their acidity (or both). The acid-gas HAP--HCl, HF, 
and HCN (representing the ``cyanide compounds'')--are water-soluble 
compounds, more soluble in water than is SO2. This indicates 
that HCl, HF, and HCN should be more easily removed from a flue gas 
stream in a typical FGD system than will SO2, even when only 
plain water is used. Hydrogen chloride is also a strong acid and will 
react easily in acid-base reactions with the caustic sorbents (e.g., 
lime, limestone) that are commonly used in FGD systems. Hydrogen 
fluoride is a weaker acid, having a similar acid dissociation constant 
as that of SO2. Cyanide is the weakest of these acid gases. 
In the slurry streams, composed of water and sorbent (e.g., lime, 
limestone) used in both wet-scrubber and dry spray dryer absorber FGD 
systems, acid gases and SO2 are absorbed by the slurry 
mixture and react to form alkaline salts. In fluidized bed combustion 
(FBC) systems, the acid gases and SO2 are adsorbed by the 
sorbent (usually limestone) that is added to the coal and an inert 
material (e.g., sand, silica, alumina, or ash) as part of the FBC 
process. Hydrogen chloride and HF have also been shown to be 
effectively removed using DSI where a dry, alkaline sorbent (e.g., 
hydrated lime, trona, sodium carbonate) is injected upstream of a PM 
control device. Chlorine in the fuel coal may also partition in small 
amounts to Cl2. This is normally a very small fraction 
relative to the formation of HCl. Limited testing has shown that 
Cl2 gas is also effectively removed in FGD systems. Although 
Cl2 is not strictly an acidic gas, it is grouped here with 
the ``acid gas HAP'' because it is controlled using the same 
technologies.
d. Expected Impact of Available Controls on HAP Emissions from EGUs
    In 2016, EGUs are projected to account for an estimated 45 percent 
of anthropogenic Hg (excluding fires) in the continental U.S. 
Application of available Hg controls in 2016 that would be required 
under section 112 reduces

[[Page 25015]]

Hg emissions from 29 down to 6 tons, achieving a 23 tpy reduction of Hg 
from EGUs, which results in a 79 percent reduction in U.S. EGU 
emissions, and a 36 percent reduction of total anthropogenic Hg 
emissions nationally.
    In 2016, EGUs are projected to account for 53 percent of total U.S. 
anthropogenic HCl. Application of available HCl controls in 2016 that 
would be required under section 112 achieves a 68,000 tpy reduction in 
HCl emissions (a 91 percent reduction in EGU emissions), resulting in a 
49 percent reduction of anthropogenic emissions nationally.
    Metal HAP emissions are a component of PM, and are expected to be 
reduced along with PM as a result of application of PM controls. In 
2016, application of controls required under section 112 is expected to 
provide an average reduction in PM for the continental U.S. of 38 
percent. Although no specific projection of metals is available for 
2016, applying the 38 percent reduction in PM to the 2010 ICR emissions 
levels of anthropogenic metals,\129\ results in reductions of 
approximately 430 tons of metals per year.\130\
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    \129\ It is generally assumed that the same types of controls 
that reduce PM will also reduce metals, because they are components 
of the PM.
    \130\ This value is 38 percent of 1,140 tons, which is the total 
tonnage of the metals listed in Table 5, based on the 2010 ICR 
emissions data.
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    EPA believes these projected reductions in Hg, acid gases, and 
metal HAP emissions demonstrate the effectiveness of available 
controls.
6. Consideration of the Role of U.S. EGU Hg Emissions in the Global 
Effort To Decrease Hg Loadings in the Environment
    This would allow the U.S. to demonstrate effective technologies to 
reduce Hg; such leadership could provide confidence to other countries 
that they can succeed in meeting their commitments. Mercury pollution 
is a significant international environmental challenge, and it is well 
understood that efforts that reduce Hg emissions in other countries 
will reduce Hg that impacts U.S. public health and the environment. 
Recognizing this, EPA and others in the U.S. Government are actively 
involved in international efforts to reduce Hg pollution. These efforts 
include global negotiations aimed at concluding a legally-binding 
agreement to reduce Hg that were initiated in February 2009 under the 
UNEP.\131\ Negotiation of the agreement is not expected to be completed 
until early 2013. Once the international process is complete, the 
agreement must be ratified domestically before the agreement will 
become binding in the U.S. The agreement is expected to cover major 
man-made sources of air Hg emissions, including coal-fired EGUs. 
Current negotiations are considering the application of best available 
technologies and practices to reduce air Hg emissions significantly. 
Regulations such as the proposed rule demonstrate the U.S. commitment 
to addressing the global Hg problem by decreasing the largest source of 
Hg emissions in the U.S. and serve to encourage other countries to 
address Hg emissions from their own sources.
---------------------------------------------------------------------------

    \131\ Governing Council of the United Nations Environment 
Programme http://www.unep.org/hazardoussubstances/Mercury/Negotiations/Mandates/tabid/3321/language/en-US/Default.aspx.
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7. 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 extensive analyses summarized above confirm that it remains 
appropriate and necessary today to regulate EGUs under section 112. It 
is appropriate to regulate emissions from coal- and oil-fired EGUs 
under CAA section 112 because: (1) Hg and non-Hg HAP continue to pose a 
hazard to public health, and U.S. EGU emissions cause and/or contribute 
to this hazard; (2) Hg and some non-Hg HAP pose a hazard to the 
environment; (3) U.S. EGU emissions, accounting for 45 percent of U.S. 
Hg emissions, are still the largest domestic source of U.S. Hg 
emissions (by 2016, EPA projects that U.S. EGU Hg emissions will be 
over 6 times larger than the next largest source, which is iron and 
steel manufacturing), as well as the largest source of HCl and HF 
emissions, and a significant source of other HAP emissions; (4) Hg 
emissions from individual EGUs leads to hot spots of deposition in 
areas directly surrounding those individual EGUs, and, thus, deposition 
is not solely the result of regionally transported emissions, and will 
not be adequately addressed through reductions in regional levels of Hg 
emissions, requiring controls to be in place at all U.S. EGU sources 
that emit Hg; (5) Hg emissions from EGUs affect not only deposition, 
exposures, and risk today, but may contribute to future deposition, 
exposure and risk due to the processes of reemission of Hg that occur 
given the persistent nature of Hg in the environment--the delay in 
issuing Hg regulations under section 112 has already resulted in 
several hundred additional tons of Hg being emitted to the environment, 
and that Hg will remain part of the global burden of Hg; and (6) 
effective controls for Hg and non-Hg HAP are available for U.S. EGU 
sources.
    EPA concludes that Hg emissions from U.S. EGUs are a public health 
hazard today due to their contribution to Hg deposition that leads to 
potential MeHg exposures above the RfD. EPA also concludes that U.S. 
EGU Hg emissions contribute to environmental concentrations of Hg that 
are harmful to wildlife and can affect production of important 
ecosystem services, including recreational hunting and fishing, and 
wildlife viewing. EPA further concludes that non-Hg HAP emissions from 
U.S. EGU are a public health hazard because they contribute to elevated 
cancer risks.
    Finally, EPA concludes that U.S. EGU's HCl and HF emissions 
contribute to acidification in sensitive ecosystems and, therefore, 
pose a risk of adverse effects on the environment.
a. U.S. EGU Hg Emissions Continue To Pose a Hazard to Public Health and 
the Environment
    The CAA does not define what constitutes a hazard to public health. 
As noted earlier, the agency must use its scientific and technical 
expertise to determine what constitutes a hazard to public health in 
the context of Utility Hg emissions. Congress did provide guidance as 
to what it considered an important benchmark for public health hazards, 
particularly in regard to Hg. In section 112(n)(1)(C), Congress 
required the NIEHS to determine ``the threshold level of Hg exposure 
below which adverse human health effects are not expected to occur.'' 
This threshold level is represented by the RfD, and as such, the RfD is 
the benchmark for determining hazards to public health that is most 
consistent with Congress's interpretation of adverse health effects. As 
a result, our assessment of the hazard to public health posed by U.S. 
EGU Hg emissions is focused on comparisons to the RfD of exposures 
caused or contributed to by U.S. EGU Hg emissions.
    As described above, almost all (98 percent) of the more than 2,400 
watersheds for which we have fish tissue data exceed the RfD, above 
which there is the potential for an increased risk of adverse effects 
on human health. U.S. EGU-attributable deposition of Hg contributes to 
a large number of those watersheds in which total potential exposures 
to MeHg from all sources exceed the RfD and, thus, pose a hazard to 
public health. For our analysis, we focused on the watersheds to which 
EGUs contributed at least 5 percent of the total Hg deposition and 
related

[[Page 25016]]

MeHg exposures at a watershed, or contributed enough Hg deposition 
resulting in potential MeHg exposures above the RfD, regardless of the 
additional deposition from other sources of Hg deposition. We believe 
this is a conservative approach because any contribution of Hg to 
watersheds where potential exposures to MeHg exceed the RfD poses a 
public health hazard. Thus, because we are finding a large percentage 
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, as we believe that 
there are additional watersheds that have contributions at lower 
percent benchmarks.
    In total, 28 percent of sampled watersheds have populations that 
are potentially at risk from exposure to MeHg based on the contribution 
of U.S. EGUs, either because U.S. EGU attributable deposition is 
sufficient to cause potential exposures to exceed the reference dose 
even before considering the deposition from other U.S. and non-U.S. 
sources, or because the U.S. EGU attributable deposition contributes 
greater than 5 percent of total deposition and total exposure from all 
sources is greater than the reference dose. At the 99th percentile fish 
consumption level for subsistence fishers, 22 percent of sampled 
watersheds where total potential exposures to MeHg exceed the RfD have 
a contribution from U.S. EGUs of at least 5 percent of Hg deposition.
    Although the most complete estimate of potential risk is based on 
total exposures to Hg, including that due to deposition from U.S. EGU 
sources, U.S. non-EGU sources, and global sources, the deposition 
resulting from U.S. EGU Hg emissions is large enough in some watersheds 
that persons consuming contaminated fish would have exposures that 
exceed the RfD even before taking into account the deposition from 
other sources. At the 99th percentile fish consumption level for 
subsistence fishers, in 12 percent of the sampled watersheds, U.S. EGUs 
are responsible for deposition that causes the RfD to be exceeded, even 
before considering the additional deposition from other sources.
    In addition, we believe the estimate of where populations may be at 
risk from U.S. EGU-attributable Hg deposition is likely understated 
because the data on fish tissue MeHg concentrations is limited in some 
regions of the U.S., such as Pennsylvania, with very high U.S. EGU 
attributable Hg deposition, and it is possible that watersheds with 
potentially high MeHg exposures were excluded from the risk 
analysis.\132\ In addition, due to limitations in our models and 
available data, we have not estimated risks in near-coastal waters, and 
some of these waters, including the Chesapeake Bay, have EGU-
attributable Hg deposition.
---------------------------------------------------------------------------

    \132\ An analysis of the impact of sampling location limitations 
on coverage of high U.S. EGU deposition watersheds is provided in 
the National Scale Mercury Risk Assessment TSD.
---------------------------------------------------------------------------

    Further, scientific studies have found strong evidence of adverse 
impacts on species of fish-eating birds with high bird-watching value, 
including loons, white ibis, and great snowy egrets. Studies have also 
shown adverse effects on insect-eating birds including many songbirds. 
Adverse effects in fish-eating mammals, such as mink and otter, include 
neurological responses (impaired escape and avoidance behavior) which 
can influence survival rates. Because EGUs contribute to Hg deposition 
in the U.S., we reasonably conclude that EGUs are contributing to the 
identified adverse environmental effects.
    Mercury emitted into the atmosphere persists for years, and once 
deposited, can be reemitted into the atmosphere due to a number of 
processes, including forest fires and melting of snow packs. As a 
result, Hg emitted today can have impacts for many years. In fact, Hg 
emitted by U.S. EGUs in the past, including over the last decade, is 
still having impacts on concentrations of Hg in fish today. 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. Although we are not able to 
quantify the impact of U.S. EGU emissions on the global pool of Hg, 
U.S. EGUs do contribute to that global pool. Controlling Hg emissions 
from U.S. EGUs helps to reduce the potential for environmental hazard 
from Hg now and in the future. These findings independently support a 
determination that it is appropriate to regulate HAP emissions from 
EGUs.
b. U.S. EGU Non-Hg HAP Emissions Continue To Pose a Hazard to Public 
Health and the Environment
    EPA recently conducted 16 case studies of U.S. EGUs for which we 
had 2007 to 2009 emissions data (based on the 2010 ICR) and that we 
anticipated would have relatively higher emissions of non-Hg HAP 
compared to other U.S. EGUs. Of the 16 facilities modeled, 4 
facilities, 3 coal and 1 oil facility, have estimated risks of greater 
than 1 in 1 million for the most exposed individual. Although section 
112(n)(1)(A) does not specify what constitutes a hazard to public 
health for the purposes of the appropriate and necessary finding, CAA 
section 112(c)(9) is instructive. As explained in section III.A above, 
for carcinogenic HAP, section 112(c)(9) contains a test for delisting 
source categories based on lifetime risk of cancer. That test reflects 
Congress' view as to the level of health effects associated with HAP 
emissions that Congress thought warranted continued regulation under 
section 112. Specifically, section 112(c)(9) provides that a source 
category can be delisted only if no source emits HAP in quantities 
which may cause a lifetime risk of cancer greater than 1 in 1 million 
to the most exposed individual. As noted above, the results of the case 
study risk analysis confirm that sources in the EGU source category 
emit HAP in quantities that cause a lifetime risk of cancer greater 
than 1 in 1 million. Given Congress' determination that categories of 
sources which emit HAP resulting in a lifetime cancer risk greater than 
1 in 1 million should not be removed from the section 112(c) source 
category list and should continue to be regulated under 112, we believe 
risks above that level represent a hazard to public health such that it 
is appropriate to regulate EGUs under section 112.
    Although our case studies did not identify significant chronic non-
cancer risks from acid gas emissions from the specific EGUs assessed, 
the Administrator remains concerned about the potential for acid gas 
emissions to add to already high atmospheric levels of other chronic 
respiratory toxicants and to environmental loading and degradation due 
to acidification. EGUs emit over half of the nationwide emissions of 
HCl and HF, based on 2010 emissions estimates. In addition, given that 
many sensitive ecosystems across the country are experiencing 
acidification, it is appropriate to reduce emissions of this magnitude 
which carry the potential to aggravate acidification. The Administrator 
concludes that, in addition to the regulation of non-Hg HAP which cause 
elevated cancer risks, 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.
    These findings independently support a determination that it is 
appropriate to regulate HAP emissions from EGUs.

[[Page 25017]]

c. Effective Controls Are Available To Reduce Hg and Non-Hg HAP 
Emissions
    Particle-bound Hg can be effectively removed along with other flue 
gas PM (including non-Hg metal HAP) in primary or secondary PM control 
devices. Electrostatic precipitators, FF, and wet FGD scrubbers are all 
effective at removing Hg, with the degree of effectiveness depending on 
the specific characteristics of the EGU and fuel types. These devices 
are all effective in removing metal HAP as well. Activated carbon 
injection is the most successfully demonstrated Hg-specific control 
technology, although performance may be reduced when used with high 
sulfur coals. Acid gases are readily removed in typical FGD systems due 
to their solubility or their acidity (or both). The availability of 
controls for HAP emissions from EGUs supports the appropriate finding 
because sources will be able to reduce their emissions effectively and, 
thereby, reduce the hazards posed by HAP emissions from EGUs.
d. The Administrator Finds That It Remains Necessary To Regulate Coal- 
and Oil-Fired EGUs Under CAA Section 112
    EPA determined that in 2016 the hazards posed to human health and 
the environment by HAP emissions from EGUs will not be addressed; 
therefore, it is necessary to regulate EGUs under section 112. In 
addition, it is necessary to regulate EGUs under section 112 because 
the only way to ensure permanent reductions in U.S. EGU emissions of 
HAP and the associated risks to public health and the environment is 
through standards set under section 112.
    The Agency first evaluates whether it is necessary to regulate HAP 
emissions from EGUs ``after imposition of the requirements of the 
CAA.'' As explained above, we interpret that phrase to require the 
Agency to consider only those requirements that Congress directly 
imposed on EGUs through the CAA as amended in 1990 and for which EPA 
could reasonably predict HAP emission reductions at the time of the 
Study. Nonetheless, the Agency recognizes that it has discretion to 
look beyond the Utility Study in determining whether it is necessary to 
regulate EGUs under section 112. Because several years have passed 
since the December 2000 Finding, we conducted an additional, updated 
analysis, examining a broad array of diverse requirements.
    Specifically, we analyzed EGU HAP emissions remaining in 2016. Our 
analysis included the proposed Transport Rule; CAA section 112(g); the 
ARP; Federal, state, and citizen enforcement actions related to 
criteria pollutant emissions from EGUs; and some state rules related to 
criteria pollutant emissions. We included state requirements and 
citizen and state enforcement action settlements associated with 
criteria pollutants because those requirements may have a basis under 
the CAA. We did not, however, conduct an analysis to determine whether 
the requirements are, in fact, based on requirements of the CAA. As 
such, we believe there may be instances where we should not have 
considered certain state rules or state and citizen suit enforcement 
settlements in our analysis, because those requirements are based 
solely in state law and are not required by Federal law. We did not 
include in our analysis any state-only requirements or voluntary 
actions to reduce HAP emissions because we knew there was no Federal 
backstop for those requirements and actions.
    Our analysis confirms that Hg emissions from EGUs remaining in 2016 
still pose a hazard to public health and the environment and, for that 
reason, it remains necessary to regulate EGUs under section 112. 
Specifically, we estimate that U.S. EGU emissions of Hg after 
imposition of the requirements of the CAA will be 29 tpy in 2016, the 
same as the level of Hg emitted today. As we stated above, we evaluated 
the hazards to public health and the environment from Hg based on the 
estimated Hg emissions in 2016 and found that a hazard exists. Because 
a hazard remains after imposition of the requirements of the CAA, it is 
necessary to regulate EGUs.
    It is necessary to regulate HAP emissions from EGUs, even though 
the hazards from Hg will not be resolved through regulation under 
section 112. EPA finds that incremental reductions in Hg are important 
because as exposure above the RfD increases the likelihood and severity 
of adverse effects increases.
    EGUs are the largest source of Hg in the U.S. and, thus, contribute 
to the risk associated with exposure to MeHg. By reducing Hg emissions 
from U.S. EGUs, this proposed rule will help to reduce the risk to 
public health and the environment from Hg exposure.
    We also find that it is necessary to regulate EGUs under section 
112 based on non-Hg HAP emissions because we cannot be certain that the 
identified cancer risks attributable to EGUs will be addressed through 
imposition of the requirements of the CAA. In addition, the 
environmental hazards posed by acidification will not be fully 
addressed through imposition of the CAA.
    We also find it necessary to regulate EGUs because regulation under 
section 112 is the only way to ensure that HAP emissions reductions 
that have been achieved since 2005 remain permanent.
    The difference between the 53 ton 2005 estimate and the 2010 ICR-
based estimate of total EGU emissions may be overstated. While EPA has 
estimated 2010 total EGU Hg emissions of 29 tons based on data from the 
2010 ICR database, this may underestimate total 2010 EGU Hg emissions 
due to the fact that emission factors used to develop the estimates may 
not accurately account for larger emissions from units with more poorly 
performing emission controls. The 2010 ICR by which the data used to 
develop the factors was collected was designed to provide the agency 
the data to determine the appropriate MACT levels and was not designed 
to collect data to fully characterize all units' Hg emissions, 
particularly those that might have poorly performing controls. EPA 
tested only 50 randomly selected units that were not selected for 
testing as best performing units (the bottom 85 percent of units), and 
we used that small sample to attempt to characterize the lower 
performing units. Because the 50 units were randomly selected, we do 
not believe we have sufficiently characterized the units that have 
poorly performing controls. In addition, the methodology for estimating 
the 2005 and 2010 emission estimates are not the same. The 2005 
estimate is based on control configurations as of 2002, therefore, it 
does not reflect reductions due to control installations that took 
place between 2002 and 2005. As a result, the apparent difference 
between 2005 and 2010 is overstated. There are real factors that 
explain why Hg reductions would have occurred between 2005 and 2010. 
The actual reductions between 2005 and 2010 are attributable to state 
Hg regulations and to CAIR and Federal enforcement actions that achieve 
Hg reductions as a co-benefit of controls for PM, NOX, and 
SO2 emissions. However, there are no national, Federally 
binding regulations for Hg. State Hg regulations can potentially change 
or be revoked without EPA approval, and reductions that occur as a co-
benefit of criteria pollutant regulations can also change. Furthermore, 
companies can change their criteria pollutant compliance strategies and 
use methodologies that do not achieve the same level of Hg or other HAP 
co-benefit (e.g., purchasing allowances in a trading program instead of 
using add-on controls).

[[Page 25018]]

    As with Hg, the most recent data on U.S. EGU HCl and HF emissions 
show a significant reduction between 2005 and 2010. These reductions in 
HCl and HF are the co-benefit of controls installed to meet other CAA 
requirements, including enforcement actions, and to a lesser extent, 
state regulations. There is no guarantee other than regulation under 
section 112 that these significant decreases in HCl and HF emissions 
will be permanent. Although we do not have estimates for the remaining 
HAP emitted from EGUs, we believe it is likely that such emissions have 
also decreased between 2005 and 2010. Thus, the Administrator finds it 
necessary to regulate HAP emissions from EGUs to ensure that HAP 
emissions reductions are permanent.
    Finally, direct control of Hg emissions affecting U.S. deposition 
is only possible through regulation of U.S. emissions; we are unable to 
control global emissions directly. Although the U.S. is actively 
involved in international efforts to reduce Hg pollution, the ability 
of the U.S. to argue effectively in these negotiations for strong 
international policies to reduce Hg air emissions depends in large part 
on our domestic policies, programs and regulations to control Hg.
    All of these findings independently support a finding that it is 
necessary to regulate EGUs under section 112.
    Therefore, given the Agency's finding that it remains appropriate 
and necessary to regulate coal- and oil-fired EGUs under CAA section 
112, EPA is confirming its inclusion of coal- and oil-fired EGUs on the 
list of source categories regulated under CAA section 112(c).
8. Implications of Hazards to Public Health for Children and 
Environmental Justice Communities
    Children are at greatest risk of adverse health effects from 
exposures to Hg, and this risk is amplified for children in minority 
and low income communities who subsist on locally-caught fish. Today's 
proposed rule is therefore an important step in addressing disparate 
impacts on children and environmental justice (EJ) communities.
    Children are more vulnerable than adults to many HAP, because of 
differences in physiology, higher per body weight breathing rates and 
consumption, rapid development of the brain and bodily systems, and 
behaviors that increase chances for exposure. Even before birth, the 
developing fetus may be exposed to HAP through the mother that affect 
development and permanently harm the individual. Infants and children 
breathe at much higher rates per body weight than adults, with infants 
under one year of age having a breathing rate up to five times that of 
adults.\133\ In addition, children breathe through their mouths more 
than adults and their nasal passages are less effective at removing 
pollutants, which leads to a higher deposition fraction in their 
lungs.\134\ Crawling and frequent hand-to-mouth activity lead to 
infants' higher levels of ingestion of contaminants deposited onto soil 
or in dust. Infants' consumption of breast milk can pass along high 
levels of accumulated persistent bioaccumulative pollutants from their 
mothers. Children's dietary intake also exceeds that of adults, per 
body weight, posing a potential added risk from persistent HAP that 
accumulate in food. In addition to the greater exposure, the less-well 
developed detoxification pathways and rapidly developing systems and 
organs put children at potentially greater risk.
---------------------------------------------------------------------------

    \133\ U.S. Environmental Protection Agency. 2006. Revision of 
the metabolically-derived ventilation rates within the Exposure 
Factors Handbook. (External review draft) Washington, DC: Office of 
Research and Development. EPA/600/R-06/129A. http://oaspub.epa.gov/eims/eimscomm.getfile?p_download_id=460261.
    \134\ Foos, B., M. Marty, J. Schwartz, W. Bennett, J. Moya, A. 
M. Jarabek, and A. G. Salmon. 2008. Focusing on children's 
Inhalation Dosimetry and Health Effects for Risk Assessment: An 
Introduction. J Toxicol Environ Health 71A: 149-165.
---------------------------------------------------------------------------

    Mercury is the HAP from EGUs of most concern to early life stages. 
The adverse affects of Hg on developing neuropsychological systems is 
well-established and permanent. The prenatal period of development has 
been established to be the most sensitive lifestage to the 
neurodevelopmental effects of MeHg.\135\ Children who are exposed to 
low concentrations of MeHg prenatally are at increased risk of poor 
performance on neurobehavioral tests, such as those measuring 
attention, fine motor function, language skills, visual-spatial 
abilities, and verbal memory.136 137 Impaired cognitive 
development from exposures to MeHg prenatally and in early childhood 
affect the individual into adulthood, by affecting learning and 
potential future earnings, and contributing to behavioral problems.
---------------------------------------------------------------------------

    \135\ National Academy of Sciences. 2000. Toxicological Effects 
of Methylmercury. Washington, DC: National Academy Press. http://books.nap.edu/catalog/9899.html?onpi_newsdoc071100.
    \136\ P. Grandjean, P. Weihe, R.F. White, F. Debes, S. Araki, K. 
Yokoyama, K. Murata, N. Sorensen, R. Dahl and P.J. Jorgensen. 1997. 
Cognitive deficit in 7-year-old children with prenatal exposure to 
methylmercury. Neurotoxicology and Teratology 19 (6):417-28.
    \137\ T. Kjellstrom, P. Kennedy, S. Wallis and C. Mantell. 1986. 
Physical and mental development of children with prenatal exposure 
to mercury from fish. Stage 1: Preliminary tests at age 4. Sweden: 
Swedish National Environmental Protection Board.
---------------------------------------------------------------------------

    Other HAP related to EGU emissions present greater risks to 
children as well. For example, mutagenic carcinogens such as 
Cr+6 have a larger impact during young lifestages, given the 
rapid development of the corporal systems.\138\ Exposure at a young age 
to these carcinogens could lead to a higher risk of developing cancer 
later in life.
---------------------------------------------------------------------------

    \138\ U.S. Environmental Protection Agency. 2005. Supplemental 
Guidance for Assessing Susceptibility from Early-Life Exposure to 
Carcinogens. Washington, DC: Risk Assessment Forum. EPA/630/R-03/
003F http://www.epa.gov/raf/publications/pdfs/childrens_supplement_final.pdf
---------------------------------------------------------------------------

    The adverse effects of individual non-Hg HAP may be more severe for 
children, particularly the youngest age groups, than adults. A number 
of epidemiologic studies suggest that children are more vulnerable than 
adults to lower respiratory symptoms associated with 
PM.139 140 Non-Hg metal HAP may behave similarly to 
particulate matter, at least in terms of the deposition fraction that 
reaches children's lungs. As with Hg, Pb and Cd are known to affect 
children's neurologic development. A meta-analysis of seven studies has 
shown an association between exposure to formaldehyde, another HAP of 
concern, and development of asthma in children.\141\
---------------------------------------------------------------------------

    \139\ Pope, C.A. and D.W. Dockery. 1992. Acute health effects of 
PM10 pollution on symptomatic and asymptomatic children. Am Rev 
Respir Dis 145: 1123-1128.
    \140\ Gauderman, W.J., R. McConnell, F. Gilliland, S. London, et 
al. 2000. Association between air pollution and lung function growth 
in Southern California children. Am J Respir Crit Care Med 162: 
1283-1390.
    \141\ McGwinn, G. Jr., J. Lienert, and J.I. Kennedy Jr. 2010. 
Formaldehyde Exposure and Asthma in Children: A Systematic Review. 
Environ Health Perspect 118: 313-317.
---------------------------------------------------------------------------

    Within communities overburdened with environmental exposures, the 
youngest lifestages are likely the most vulnerable. Looking at the 
health effects for children in those communities can be an important 
part of appropriately assessing community risks.
    EPA has also considered the effects of this rule on EJ communities. 
The nature of exposures to Hg is such that populations with high levels 
of self-caught fish consumption are likely to be disproportionately 
affected. EPA's risk analysis identified many EJ communities, including 
Laotian, Vietnamese, Hispanic, African-American, tribal, and low income 
communities, as having higher levels of subsistence fishing activities. 
Consequently, individuals in these

[[Page 25019]]

communities are potentially exposed to levels of MeHg in fish that may 
result in these individuals' exposure exceeding the RfD. These EJ 
populations are thus at higher risk for the health effects associated 
with exposures to MeHg, which include impacts on neurological functions 
that can cause children to struggle in school. In EJ populations which 
often face numerous other stressors that can result in lower 
educational performance, the additional burdens imposed by exposure to 
Hg may cause significant and long-lasting impacts on children that 
continue into adulthood, affecting learning potential and measures of 
IQ, including future earnings and indicators of quality of life.
9. The Analysis Supporting the 2005 Action Was Subject to Technical 
Limitations and These Flaws Undermine the Basis for the 2005 Action
    In 2005, EPA conducted a set of technical analyses to support a 
revision to the 2000 appropriate and necessary finding.\142\ In those 
analyses, EPA made several assumptions that were not justified based on 
scientific or technical grounds, and which we have corrected in our 
technical analysis supporting our current confirmatory finding that it 
is appropriate and necessary to regulate coal- and oil-fired EGUs under 
section 112.
---------------------------------------------------------------------------

    \142\ U.S. EPA. 2005. Technical Support Document: Methodology 
Used to Generate Deposition, Fish Tissue Methylmercury 
Concentrations, and Exposure for Determining Effectiveness of 
Utility Emission Controls.
---------------------------------------------------------------------------

a. Interpretation of the MeHg Reference Dose and Incremental U.S. EGU-
Attributable Exposures
    In the 2005 analysis, EPA made the following statement:
    The RfD provides a useful reference point for comparisons with 
measured or modeled exposure. The Agency defines the RfD as an exposure 
level below which the Agency believes exposures are likely to be 
without an appreciable risk over a lifetime of exposure. For the 
purposes of assessing population exposure due to EGUs, we create an 
index of daily intake (IDI). The IDI is defined as the ratio of 
exposure due solely to EGUs to an exposure of 0.1 [mu]g/kg bw/day. The 
IDI is defined so that an IDI of 1 is equal to an incremental exposure 
equal to the RfD level, recognizing that the RfD is an absolute level, 
while the IDI is based on incremental exposure without regard to 
absolute levels. Note that an IDI value of 1 would represent an 
absolute exposure greater than the RfD when background exposures are 
considered.\143\
---------------------------------------------------------------------------

    \143\ U.S. EPA. 2005. Technical Support Document: Methodology 
Used to Generate Deposition, Fish Tissue Methylmercury 
Concentrations, and Exposure for Determining Effectiveness of 
Utility Emission Controls.
---------------------------------------------------------------------------

    Upon further consideration, EPA concludes that it did not have a 
scientific or technical justification for creating a metric other than 
the HQ \144\ to compare U.S. EGU-attributable exposures to the RfD. As 
EPA recognized in 2005, the RfD is an absolute level above which the 
potential risks of exposures increase, based on total exposures to 
MeHg. The concept of the IDI was created by EPA in 2005 solely to 
support its interpretation that it must assess hazards to public health 
solely based on U.S. EGU emissions with no consideration of exposures 
to MeHg arising from other sources of Hg deposition. As noted above, 
nothing in section 112(n)(1)(A) prohibits consideration of HAP 
emissions from U.S. EGUs in conjunction with HAP emissions from other 
sources of HAP, including sources outside the U.S. Indeed, such an 
approach would ignore the manner in which the public is actually 
exposed to HAP emission. By focusing on whether incremental exposures 
attributable to U.S. EGU Hg emissions exceeded the RfD without 
consideration of other exposures, EPA implied that U.S. EGU Hg 
emissions were not causing a hazard to public health even though such 
emissions were increasing risks in locations where the RfD was already 
exceeded due to total exposures from all Hg sources, including U.S. EGU 
emissions. This is a serious flaw in EPA's 2005 assessment, due to 
reasons we discuss below.
---------------------------------------------------------------------------

    \144\ The HQ is the ratio of observed or modeled exposures to 
the RfD.
---------------------------------------------------------------------------

    Ninety-eight percent of watersheds with fish tissue MeHg samples 
have Hg deposition levels such that total potential exposure to MeHg 
exceeds the RfD, and many have exposures that are many times the 
RfD.\145\ As a result, in almost all watersheds with fish tissue MeHg 
samples, any additional Hg will increase potential risk. Thus, U.S. 
EGU-attributable Hg deposition is contributing to increased potential 
risk. The Agency believes the assessment of potential risk due to Hg 
emissions from U.S. EGUs must consider both the extent to which U.S. 
EGUs contribute to such risk along with other sources, and the extent 
to which U.S. EGU-attributable deposition leads to exposures that 
exceed the RfD even before considering the contributions of other 
sources of Hg. The Agency has conducted such an evaluation in the 
national-scale MeHg risk analysis presented above. In 2005, as a result 
of relying on a flawed, non-scientific approach for comparing MeHg 
exposures to the RfD, and a failure to consider cumulative risk 
characterization metrics, EPA incorrectly determined that U.S. EGU 
emissions of Hg did not constitute a hazard to public health. As 
discussed above, EPA has revised this determination and concluded that 
U.S. EGU Hg emissions are a hazard to public health because they cause 
exposures to exceed the RfD or contribute to exposures in watersheds 
where total exposures to MeHg exceed the RfD.
---------------------------------------------------------------------------

    \145\ See the National Scale Mercury Risk Assessment Technical 
Support Document.
---------------------------------------------------------------------------

b. Interpretation of Populations Likely To Be at Risk and Conclusions 
Regarding Acceptable Risk
    In addition to developing a flawed exposure indicator based on only 
U.S. EGU attributable exposure (the IDI), EPA also erred in finding 
that exposures above the RfD (an IDI greater than 1) did not pose an 
``unacceptable risk'' (e.g., did not pose a hazard to public health). 
EPA cited three reasons for the finding in 2005: (1) Lack of confidence 
in the risk estimates; (2) lack of seriousness of the health effects of 
MeHg; and (3) small size of the population at risk and low probability 
of risks in that population. EPA was not justified in making its 
determination based on these three factors.
    In the 2005 Action, EPA cited the underpinnings of the RfD as 
introducing a degree of conservatism. In fact, however, as discussed 
above, EPA has stated consistently, including in the RfD issued in 
2001, that the RfD for Hg is a level above which there is the potential 
for increased risk. Only at levels at or below the RfD does the Agency 
maintain that exposures are without significant risk. EPA's 
interpretation in 2005 was a departure from prior EPA policy as it 
concerns exposures to Hg and was in error.
    In the 2005 Action, EPA identified risk of poor performance on 
neurobehavioral tests, such as those measuring attention, fine motor 
function, language skills, visual-spatial abilities (like drawing), and 
verbal memory as the primary health effects of MeHg exposures. Although 
not stated explicitly, it is implicit in the 2005 Action that EPA did 
not consider these health effects to be serious. The Agency did not, 
and could not have, provided any scientific or policy rationale for 
dismissing these serious public health effects. For example, as 
mentioned

[[Page 25020]]

above, there are potentially serious implications of the identified 
effects on learning potential and measures of IQ, including future 
earnings and indicators of quality of life. EPA was not justified in 
dismissing these health effects as not serious without providing 
evidence or justification, which it could not do based on the 
information available at the time or today.
    In the 2005 Action, EPA made several statements in the technical 
analysis suggesting that the probability that an IDI of 1 would be 
exceeded (e.g., that U.S. EGU attributable exposures would be greater 
than the RfD) was low due to the rare occurrence of high consumption 
rate populations in high deposition watersheds. The 2005 analysis 
showed that 15 percent of watersheds would have U.S. EGU-attributable 
potential exposures that were twice the RfD for the highest fish 
consumption rates. EPA dismissed this high percent of watersheds by 
stating that those high fish consumption rates would only occur in 
Native American populations, and that those populations lived in 
locations that were not heavily impacted by U.S. EGU Hg deposition.
    Information was available at the time of the 2005 analysis 
indicating that other populations besides Native Americans engaged in 
subsistence fishing activities that would result in consumption rates 
similar to Native Americans. EPA chose to selectively use information 
only on Native American consumption rates and erroneously concluded 
that subsistence fishing activities would not occur in a wider set of 
locations. This choice was in error, as EPA should have investigated 
whether other subsistence populations could fish in locations heavily 
impacted by U.S. EGU emissions (e.g., watersheds with the top 15 
percent of U.S. EGU-attributable fish tissue MeHg levels). A search of 
the literature available in 2005 reveals several studies that 
identified additional fishing populations with subsistence or near 
subsistence consumption rates, including urban fishing populations 
(including low-income populations),146 147 148 Laotian 
communities,\149\ and Hispanics. In fact, EPA participated in 1999 in a 
project investigating exposures of poor, minority communities in New 
York City to a number of contaminants including Hg, and should thus 
have been aware that these populations can have very high consumption 
rates.\150\ If EPA had conducted a thorough investigation in 2005, it 
should have concluded that populations with the potential for 
subsistence-level fish consumption rates occur in many watersheds, and, 
thus, could not have concluded that exposures above the RfD (IDI 
greater than 1) were not likely.
---------------------------------------------------------------------------

    \146\ Burger, J., K. Pflugh, L. Lurig, L. Von Hagen, and S. Von 
Hagen. 1999. Fishing in Urban New Jersey: Ethnicity Affects 
Information Sources, Perception, and Compliance. Risk Analysis 
19(2): 217-229.
    \147\ Burger, J., Stephens, W., Boring, C., Kuklinski, M., 
Gibbons, W.J., & Gochfield, M. (1999). Factors in exposure 
assessment: Ethnic and socioeconomic differences in fishing and 
consumption of fish caught along the Savannah River. Risk Analysis, 
19(3).
    \148\ 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, California Environmental 
Protection Agency, July 1997.
    \149\ Tai, S. 1999. ``Environmental Hazards and the Richmond 
Laotian American Community: A Case Study in Environmental Justice.'' 
Asian Law Journal 6: 189.
    \150\ 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).
---------------------------------------------------------------------------

    Thus, based on the errors EPA made in the 2005 Action related to 
evaluating the risks from MeHg exposures attributable to U.S. EGUs, 
EPA's technical determination in 2005 that risks were acceptable based 
on that analysis was not justified. As a result the technical 
determination in 2005 which supported the finding of no public health 
hazard, and the determination that it was not appropriate or necessary 
to regulate HAP from U.S. EGUs was in error.

IV. Summary of This Proposed NESHAP

    This section summarizes the requirements proposed in this proposed 
rule. Our rationale for the proposed requirements is provided in 
Section V of this preamble.

A. What source categories are affected by this proposed rule?

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

B. What is the affected source?

    An existing affected source for this proposed rule is the 
collection of coal- and oil-fired EGUs within a single contiguous area 
and under common control. A new affected source is a coal- or oil-fired 
EGU for which construction or reconstruction began after May 3, 2011.
    CAA section 112(a)(8) defines an EGU as:

    a fossil fuel-fired combustion unit of more than 25 megawatts 
electric (MWe) 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 MWe output to any utility power distribution system for 
sale is also 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 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. As noted below, EPA is proposing a definition to 
determine whether the combustion unit is ``fossil fuel fired'' such 
that it is an EGU for purposes of this proposed rule. The unit must be 
capable of combusting more than 73 megawatt-electric (MWe) (250 million 
British thermal units per hour, MMBtu/hr) heat input (equivalent to 25 
MWe electrical output) of coal or oil. In addition, using the construct 
of the definition of ``oil-fired'' from the ARP, we are proposing that 
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 to be considered a ``fossil fuel fired'' EGU subject to 
this proposed rule. If a new or existing EGU is not coal- or oil-fired, 
and the unit burns 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 percent or more of the annual heat input during 
any 1 of those calendar years, the unit is considered to be natural 
gas-fired and would not be subject to this proposed rule. As discussed 
later, we believe that this definition will address those situations 
where either an EGU fires coal or oil on only a limited basis or co-
fires limited amounts of coal or oil with other non-fossil fuels (e.g., 
biomass).
    To the extent a unit combusts solid waste, that unit is not an EGU 
under section 112, but rather would be subject to CAA section 129.
    The Small Entity Representatives (SERs) serving on the Small 
Business Advocacy Review Panel (SBAR) established under the Small 
Business Regulatory Enforcement Fairness Act (SBREFA) suggested that 
EPA consider developing an area-source (i.e., those EGUs emitting less 
than 10 tpy of any one HAP or less than 25 tpy of any combination of 
HAP) vs. major-source (i.e., those EGUs emitting 10 tpy or more of any 
one HAP or 25 tpy of more of any

[[Page 25021]]

combination of HAP) distinction for this source category. The proposed 
rule treats all EGUs the same and proposes MACT standards for all 
units.
    Nothing in the CAA requires that we issue GACT standards for area 
sources. Indeed, here, the data show that similar HAP emissions and 
control technologies are found on both major and area sources greater 
than 25 MWe. 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, 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. There are EGUs that are 
physically quite large that are area sources, and EGUs that are small 
that are major sources. Both large and small EGUs are represented in 
the MACT floor pools for acid gas, Hg, and non-Hg metal HAP. Finally, 
given that EPA is regulating both major and area source EGUs at the 
same time in this rulemaking, a common control strategy consequently 
appears warranted for these emissions.
    If area sources tend to be very different from major sources and 
the capacity to control those sources is different, we could exercise 
our discretion under section 112(d)(5) to set GACT standards for area 
sources. But, as explained above, that is not the case here. 
Accordingly, we believe it is appropriate to set MACT standards for 
both major and area source EGUs. EPA solicits comment on its proposed 
approach. Specifically, we solicit comments on whether there would be a 
basis for considering area sources to be significantly different from 
major sources with respect to issues relevant to standard setting. 
Commenters should also explain the basis of their suggested approach 
and how that approach would lead to similar health and environmental 
benefits, including data that would underpin a GACT analysis.\151\
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    \151\ As we have explained in other rules, determining what 
constitutes GACT involves considering the control technologies and 
management practices that are generally available to the area 
sources in the source category. We also consider the standards 
applicable to major sources in the same industrial sector to 
determine if the control technologies and management practices are 
transferable and generally available to area sources. In appropriate 
circumstances, we may also consider technologies and practices at 
area and major sources in similar categories to determine whether 
such technologies and practices could be considered generally 
available for the area source category at issue. Finally, in 
determining GACT for a particular area source category, we consider 
the costs and economic impacts of available control technologies and 
management practices on that category.
---------------------------------------------------------------------------

C. Does this proposed rule apply to me?

    This proposed rule applies to you if you own or operate a coal- or 
oil-fired EGU as defined in this proposed rule.

D. Summary of Other Related DC Circuit Court Decisions

    In March 2007, the DC Circuit Court issued an opinion (Sierra Club 
v. EPA, 479 F.3d 875 (DC Cir. 2007)) (Brick MACT) vacating and 
remanding CAA section 112(d) NESHAP for the Brick and Structural Clay 
Ceramics source categories. Some key holdings in that case were:
     Floors for existing sources must reflect the average 
emission limitation achieved by the best-performing 12 percent of 
existing sources, not levels EPA considers to be achievable by all 
sources (479 F.3d at 880-81);
     EPA cannot set floors of ``no control.'' The DC Circuit 
Court reiterated its prior holdings, including National Lime Ass'n. v. 
EPA (233 F.3d625 (DC Cir. 2000)) (National Lime II), confirming that 
EPA must set floor standards for all HAP emitted by the source, 
including those HAP that are not controlled by at-the-stack control 
devices (479 F.3d at 883);
     EPA cannot ignore non-technology factors that reduce HAP 
emissions. Specifically, the DC Circuit Court held that ``EPA's 
decision to base floors exclusively on technology even though non-
technology factors affect emissions violates the Act.'' (479 F.3d at 
883.) The DC Circuit Court also reiterated its position stated in 
Cement Kiln Recycling Coalition v. EPA, 255 F.3d 855 (DC Cir. 2001) 
that CAA section 112(d)(3) ``requires floors based on the emission 
level actually achieved by the best performers (those with the lowest 
emission levels).''
    Based on the Brick MACT decision, we believe a source's performance 
resulting from the presence or absence of HAP in fuel materials must be 
accounted for in establishing floors (i.e., a low emitter due to low 
HAP fuel materials can still be a best performer). In addition, the 
fact that a specific level of performance is unintended is not a legal 
basis for excluding the source's performance from consideration. 
National Lime II; 233 F.3d at 640.
    The Brick MACT decision also stated that EPA may account for 
variability in setting floors. The DC Circuit Court found that ``EPA 
may not use emission levels of the worst performers to estimate 
variability of the best performers without a demonstrated relationship 
between the two.'' 479 F.3d at 882.
    A second DC Circuit Court opinion is also relevant to this 
proposal. In Sierra Club v. EPA, 551 F.3d 1019 (DC Cir. 2008), the DC 
Circuit Court vacated the portion of the regulations contained in the 
General Provisions which exempt major sources from NESHAP during 
periods of startup, shutdown and malfunction (SSM). The regulations (in 
40 CFR 63.6(f)(1) and 63.6(h)(1)) provided that sources need not comply 
with the relevant CAA section 112(d) standard during SSM events and 
instead must ``minimize emissions * * * to the greatest extent which is 
consistent with safety and good air pollution control practices.'' As a 
result of the DC Circuit Court decision, sources must comply with the 
emission standards at all times and we are addressing SSM in this 
proposed rulemaking. Discussion of this issue may be found later in 
this preamble.
    A third relevant DC Circuit Court opinion is National Lime II (233 
F.3d 625), where, in considering whether EPA may use PM, a criteria 
pollutant, as a surrogate for metal HAP, the DC Circuit Court stated 
that EPA ``may use a surrogate to regulate hazardous pollutants if it 
is `reasonable' to do so'' and laid out criteria establishing a three-
part analysis for determining whether the use of PM as a surrogate for 
non-Hg metal HAP was reasonable. The DC Circuit Court found that PM is 
a reasonable surrogate for HAP if: (1) ``HAP metals are invariably 
present in * * * PM;'' (2) ``PM control technology indiscriminately 
captures HAP metals along with other particulates;'' and (3) ``PM 
control is the only means by which facilities `achieve' reductions in 
HAP metal emissions.'' 233 F.3d at 639. If these criteria are satisfied 
and the PM emission standards reflect what the best sources achieve--
complying with CAA section 7412(d)(3)--``EPA is under no obligation to 
achieve a particular numerical reduction in HAP metal emissions.'' We 
have considered this case in evaluating whether the surrogate standards 
we propose to establish in this proposed rule are reasonable.

E. EPA's Response to the Vacatur of the 2005 Action

    After the vacatur of the Revision Rule, EPA evaluated the HAP and 
other emissions data available to establish CAA section 112(d) 
standards for coal- and oil-fired EGUs and determined that additional 
HAP emission data were required. EPA initiated an information 
collection effort entitled ``Electric Utility Steam Generating Unit 
Hazardous Air Pollutant Emissions Information

[[Page 25022]]

Collection Effort'' (OMB Control Number 2060-0631). This information 
collection (2010 ICR) was conducted by EPA's Office of Air and 
Radiation (OAR) pursuant to CAA section 114 to assist the Administrator 
in developing emissions standards for coal- and oil-fired EGUs pursuant 
to CAA section 112(d). CAA section 114(a) states, in pertinent part:

    For the purpose of * * * (iii) carrying out any provision of 
this Chapter * * * (1) the Administrator may require any person who 
owns or operates any emission source * * * to * * * (D) sample such 
emissions (in accordance with such procedures or methods, at such 
locations, at such intervals, during such periods and in such manner 
as the Administrator shall prescribe); (E) keep records on control 
equipment parameters, production variables or other indirect data 
when direct monitoring of emissions is impractical * * *; (G) 
provide such other information as the Administrator may reasonably 
require * * *

    Prior to issuance of the information collection effort, information 
necessary to identify all coal- and oil-fired EGUs as defined in CAA 
section 112(a)(8) was publicly available for EGUs owned and operated by 
publicly-owned utility companies, Federal power agencies, rural 
electric cooperatives, investor-owned utility generating companies, and 
nonutility generators (such units include, but may not be limited to, 
independent power producers (IPPs), qualifying facilities, and combined 
heat and power (CHP) units). The most recent information available was 
for 2005, and the available information generally did not include any 
information on permitted HAP emission limits; or monitoring, 
recordkeeping, and reporting requirements for HAP emissions; and we did 
not have complete HAP emissions data for any EGU. Additionally, we had 
little current information on the fuel amounts received, fuel sources, 
fuel shipment methods, or results of previously conducted fuel analyses 
for coal- and oil-fired EGUs, or for results from tests conducted since 
January 1, 2005. We did not have emissions test results that would 
provide data for emissions of a variety of pollutants, including: PM, 
PM with an aerodynamic diameter equal to or less than 2.5 micrometers 
(PM2.5); SO2; HCl/HF/HCN; metal HAP (including 
compounds of Sb, As, Be, Cd, Cr, Co, Pb, Mn, Ni, and Se); Hg; total 
organic hydrocarbons (THC); volatile organic compounds (VOC); and 
carbon monoxide (CO).
    To obtain the information necessary to evaluate coal- and oil-fired 
EGUs, EPA developed a two-phase ICR and published the first notice in 
the Federal Register for comment consistent with the requirements of 
the PRA. 74 FR 31725 (July 2, 2009). We received comments from industry 
and other interested parties. We also met with industry and other 
interested parties, and published a revised ICR in the Federal Register 
for another round of comments consistent with the PRA. 74 FR 58012 
(November 10, 2009). OMB approved the ICR on December 24, 2009, and we 
sent the ICR to owners and operators of EGUs on December 31, 2010.
    As stated above, the ICR contained two phases or components. The 
first component solicited information from all potentially affected 
units. EPA provided the survey in electronic format; however, written 
responses were also accepted. The survey was submitted to all coal- and 
oil-fired EGUs listed in the 2007 version of the DOE's Energy 
Information Administration's (EIA) Forms 860 and 923, ``Annual Electric 
Generator Report,'' and ``Power Plant Operations Report,'' 
respectively.
    The second component required the owners/operators of a limited 
number of coal-and oil-fired EGUs to conduct stack testing in 
accordance with an EPA-approved protocol. Some coal-fired units were 
selected to be tested because we determined based on the information 
available that the units were among the top performing 15 percent of 
sources in the coal subcategory for certain types of HAP. Best-
performing coal-fired units to be tested were selected to cover three 
groups of HAP that may be regulated through the use of surrogate 
standards: (1) Non-Hg metallic HAP (e.g., As, Pb, Se); (2) acid gas HAP 
(e.g., HCl, HF, HCN); (3) and non-dioxin/furan organic HAP. We also 
required the non-Hg metallic HAP sources to test for Hg even though Hg 
is to be regulated separately and not covered by any non-Hg metallic 
HAP surrogacy. Fifty coal-fired units were also selected at random from 
the entire population of coal-fired EGUs to test for dioxin/furan 
organic HAP. An additional 50 coal-fired units were selected at random 
from among those units not selected as being ``top performing'' units 
to represent those coal-fired units not comprising the top-performing 
units in the three HAP surrogate groups; these 50 randomly selected 
units were required to test for all HAP except dioxin/furan organic 
HAP. Data from this last grouping was collected so we could estimate 
the HAP emission reductions associated with the proposed standards. 
Oil-fired units to be tested were also selected at random to test for 
HAP in all three groups of HAP noted above, in addition to testing for 
Hg and dioxin/furan.
    The testing consisted of three runs at the sampling location and 
was in accordance with a specified emission test method. The owner/
operator of each selected EGU was also required to collect and analyze, 
in accordance with an acceptable procedure, three fuel samples from the 
fuel fed to the EGU during each stack test. Additional details of the 
required sampling may be found in Docket entry EPA-HQ-OAR-2009-0234-
0062.
    In phase one, all coal- and oil-fired EGUs identified by EPA as 
being potentially subject sources under the definition in CAA section 
112(a)(8), including all integrated gasification combined cycle (IGCC) 
EGUs and all EGUs fired by petroleum coke, were required to submit 
information to EPA. The sources were required to provide information on 
the current operational status of the unit, including applicable 
controls installed, along with emissions information from the preceding 
5 years. This information was necessary for EPA to fully characterize 
the category and update our database of coal- and oil-fired EGUs.
    Phase two was the testing phase. As stated above, coal-fired units 
to be tested were selected to cover five HAP or groups of HAP, three of 
which may be regulated through the use of surrogate pollutant standards 
and were chosen because EPA determined the units were best performing 
units for one or more of the three HAP surrogate groups. In the stack 
testing, each facility was required to test after the last control 
device or at the stack if the stack is not shared with other units 
using different controls. In this way, the facility would test before 
any ``dilution'' by gases from a separately-controlled unit. Under 
certain circumstances, however, testing after a common control device 
or at the common stack was allowed.
    EPA selected for testing the sources that the Agency believed, 
based on a variety of factors and information available to the Agency 
at the time, were the best performing sources for the three HAP 
surrogate groups for which they were required to test. In targeting the 
best performing sources, EPA required testing for approximately 15 
percent of all coal-fired EGUs for the 3 HAP surrogate groups--non-Hg 
metal HAP and PM; non-dioxin/furan organic HAP, total hydrocarbon, CO, 
and VOC; and acid gas HAP and SO2. As we stated in response 
to comments on the proposed 2010 ICR, we targeted the best performing 
coal-fired sources for certain HAP groups because the statute requires 
the Agency to set the MACT floor at the ``average emission limitation 
achieved by the best performing 12 percent of the

[[Page 25023]]

existing sources (for which the Administrator has information)'' in the 
category. By targeting the best performing 15 percent of coal-fired 
EGUs for testing in the 3 HAP groups, we concluded that we would have 
emissions data on the best performing 12 percent of all existing coal-
fired EGUs. In this proposed rule, we used data from sources 
representing the best performing 12 percent of all sources in any 
category or subcategory to establish the CAA section 112(d) standards 
for the 3 HAP groups because we believe we have identified the best 
performing 12 percent of sources for those subcategories with 30 or 
more sources. For Hg from coal-fired units, we used the top 12 percent 
of the data obtained because, even though we required Hg testing for 
the units testing for the non-Hg metallic HAP, we did not believe those 
units represented the top performing 12 percent of sources for Hg in 
the category at the time we issued the ICR and we made no assertions to 
that effect. For oil-fired units, we also used the top 12 percent of 
the data obtained because we were unable, based on the information 
available, to determine the best performing oil-fired units. The 
primary reason for our inability to identify best performing oil-fired 
units is that such units are generally uncontrolled or controlled only 
with an ESP. The approach for both coal- and oil-fired EGUs was 
discussed with, and agreed upon by, several industry and environmental 
organization stakeholders prior to finalizing the ICR.
    The acid-gas HAP, HCl and HF, are water-soluble compounds and are 
more soluble in water than is SO2. (Cyanide, representing 
the ``cyanide compounds,'' and Cl2 gas are also water-
soluble and are considered ``acid-gas HAP'' in this proposal.) Hydrogen 
chloride also has a large acid dissociation constant (i.e., HCl is a 
strong acid) and it, thus, will react easily in an acid-base reaction 
with caustic sorbents (e.g., lime, limestone). The same is true for HF. 
This indicates that both HCl and HF will be more rapidly and readily 
removed from a flue gas stream than will SO2, even when only 
plain water is used. In FBC systems, the acid gases and SO2 
are adsorbed by the sorbent (usually limestone) that is added to the 
coal and an inert material (e.g., sand, silica, alumina, or ash) as 
part of the FBC process.
    Hydrogen chloride and HF have also been shown to be effectively 
removed using DSI where a dry, alkaline sorbent (e.g., hydrated lime, 
trona, sodium carbonate) is injected upstream of a PM control device.
    Chlorine in the fuel coal may also partition in small amounts to 
Cl2. This is normally a very small fraction relative to the 
formation of HCl. Limited testing has shown that Cl2 gas is 
also effectively removed in FGD systems. Although Cl2 is not 
strictly an acidic gas, it is grouped here with the ``acid gas HAP'' 
because it is controlled using the same technologies.
    Because the technologies for removal of the acid gases are 
primarily those that are also used for FGD, we consider emissions of 
SO2, a commonly measured pollutant, as a potential surrogate 
for emissions of the acid-gas HAP HCl, HF, HCN, and Cl2. 
Although use of SO2 as a surrogate for acid gas HAP has not 
been used in any CAA section 112 rules by EPA, it has been used in a 
number of state permitting actions (see Docket entry EPA-HQ-OAR-2009-
0234-0062). Hydrogen chloride has been used as a surrogate for the acid 
gas HAP in other Agency actions (e.g., Portland Cement NESHAP, 75 FR 
54970, September 9, 2010 (final rule); major and area source 
Industrial, Commercial, and Institutional Boilers and Process Heaters 
NESHAP (collectively, Boiler NESHAP), 75 FR 32005, June 4, 2010; 75 FR 
31895, June 4, 2010 (proposed rules; the final rules were signed on 
February 21, 2011)), and we propose to use HCl as a surrogate for all 
the acid gas HAP, with an alternative equivalent standard using 
SO2 as a surrogate. In addition, we gathered sufficient data 
on HCl, HF, and HCN \152\ to establish individual emission limitations 
if warranted.
---------------------------------------------------------------------------

    \152\ Although the combination of extended sampling times and 
stack chemistry for many units in this source category rendered the 
test method for HCN unreliable, yielding suspect HCN results, we 
still consider SO2 or HCl emissions to be adequate 
surrogates for HCN emissions.
---------------------------------------------------------------------------

    EPA identified the units with the newest FGD controls installed for 
testing of acid gas HAP based on our analysis that FGD controls are the 
best at reducing acid gas HAP emissions. EPA also believes that the 
units with the newest FGD systems represent those units having to 
comply with the most recent, and, therefore, likely most stringent, 
emission limits for SO2. We determined that efforts by units 
to comply with stringent SO2 limits would also likely 
represent the top performers with regard to acid gas HAP emissions. 
Specifics of the required testing may be found in Docket entry EPA-HQ-
OAR-2009-0234-0062.
    Dioxin/furan emissions data were obtained in support of the 1998 
Utility Report to Congress. However, approximately one-half of those 
data were listed as being below the minimum detection level (MDL) for 
the given test. Dioxin/furan emissions from coal-fired EGUs are 
generally considered to be low, presumably because of the insufficient 
amounts of available chlorine. As a result of previous work conducted 
on municipal waste combustors (MWC), it has also been proposed that the 
formation of dioxins and furans in exhaust gases is inhibited by the 
presence of sulfur.\153\ Further, it has been suggested that if the 
sulfur-to-chlorine ratio (S:Cl) in the flue gas is greater than 1.0, 
then formation of dioxins/furans is inhibited.154 155 The 
vast majority of the coal analyses provided through the 1999 ICR effort 
indicated S:Cl values greater than 1.0. As a result, EPA expected that 
additional data gathering efforts would continue the trend of data 
being at or below the MDL. Even so, EPA believed it necessary to 
collect some additional data so that the trend could be affirmed or 
rejected for EGUs. If the trend were rejected, then EPA would be able 
to establish an emission limit for dioxin/furan; however, if the trend 
were affirmed, then EPA would need to seek alternatives to an emissions 
limit, such as a work practice standard. The latter approach might 
become necessary because measurements made at or below MDL generally 
indicate the presence, but not the exact quantity, of a substance. In 
addition, measurements made at or below the MDL have an accuracy on the 
order of plus or minus 50 percent, whereas other environmental 
measurements used by EPA in other rulemakings exhibit accuracies of 
plus or minus up to 15 percent. Sampling and analytical methods for 
dioxins/furans have improved since the 1990's work, so their MDLs are 
expected to have decreased. Moreover, for this sampling effort, we 
required sampling periods to be extended up to eight times longer than 
normal to collect more sample volume, thus, hopefully improving 
detection capability. Note that although longer sampling periods can be 
obtained during short term emissions testing, maintaining such longer 
sampling times

[[Page 25024]]

becomes impractical, if not infeasible, for continuous monitoring.
---------------------------------------------------------------------------

    \153\ Gullett, BK, et al. Effect of Cofiring Coal on Formation 
of Polychlorinated Dibenzo-p-Dioxins and Dibenzofurans during Waste 
Combustion. Environmental Science and Technology. Vol. 34, No. 
2:282-290. 2000.
    \154\ Raghunathan, K, and Gullett, BK. Role of Sulfur in 
Reducing PCDD and PCDF Formation. Environmental Science and 
Technology. Vol. 30, No. 6:1827-1834. 1996.
    \155\ Li., H, et al. Chlorinated Organic Compounds Evolved 
During the combustion of Blends of Refuse-derived Fuels and Coals. 
Journal of Thermal Analysis. Vol. 49:1417-1422. 1997.
---------------------------------------------------------------------------

    For these reasons, we selected 50 units at random from the entire 
coal-fired EGU population to conduct emission testing for dioxins/
furans. EPA has identified AC as a potential control technology for 
dioxin/furan control based on results of previous work done on MWC 
units, and several of the units that were selected for testing have ACI 
systems that had been installed for Hg control. Specifics of the 
required testing may be found in Docket entry EPA-HQ-OAR-2009-0234-
0062.
    Emissions of CO, VOC, and/or THC have, in the past, been used as 
surrogates for the non-dioxin/furan organic HAP based on the theory 
that efficient combustion leads to lower organic emissions (Portland 
Cement NESHAP--THC (75 FR 54970; September 9, 2010); Boiler NESHAP--CO 
(75 FR 32005, June 4, 2010; 75 FR 31895, June 4, 2010 (proposed rules; 
the final rules were signed on February 21, 2011)); Hazardous Waste 
Combustor NESHAP--CO (64 FR 52828; September 30, 1999)). Although 
indications are that organic HAP emissions are low (and perhaps below 
the MDL), there were very few emissions data available for these 
compounds from coal-fired EGUs and we determined that it was necessary 
to obtain additional information on which to establish standards for 
these HAP. EPA identified the newest units as being representative of 
the most modern, and, thus, presumed most efficient units. The 170 
newest units were selected and were required to test for CO, VOC, and 
THC; specifics of the required testing may be found in Docket entry 
EPA-HQ-OAR-2009-0234-0062.
    Emissions of certain non-Hg metallic HAP (i.e., Sb, Be, Cd, Cr, Co, 
Pb, Mn, and Ni) have been assumed to be well controlled by PM control 
devices. However, Hg and other non-Hg metallic HAP (i.e., As and Se), 
have the potential to exist in both the particulate and vapor phases, 
and, therefore, may not be well controlled by PM control devices alone. 
Also, it has been shown through recent stack testing that certain of 
these HAP (i.e., As and Se) may condense on (or as) very fine PM in the 
emissions from coal-fired units. There are very few recent emissions 
test data available showing the potential control of these metallic HAP 
from coal-fired EGUs.
    EPA identified the units with the newest PM controls installed as 
the units to test for non-Hg metal HAP. EPA believed that these units 
represent those units having to comply with the most recent, and, 
therefore, likely most stringent, emission limits for PM. EPA believes 
units complying with stringent PM limits represent the top performers 
with regard to non-Hg metallic HAP emissions, even for those HAP that 
may at times form in other than the particulate phase. The units 
selected also included a number with ACI installed. The 170 units with 
the newest PM controls installed were selected and were required to 
test after that specific PM control (or at the stack if the PM control 
device is not shared with one or more other units); specifics of the 
required testing may be found in Docket entry EPA-HQ-OAR-2009-0234-
0062.
    The capture of Hg is dependent on several factors including the 
chloride content of the coal, the sulfur content of the coal, the 
amount of unburned carbon present in the fly ash, and the flue gas 
temperature profile. All of these factors affect the chemical form (the 
speciation) of Hg in the flue gas. Mercury may exist as Hg\0\, as 
Hg\+2\ (or reactive gaseous Hg, RGM) or as Hgp. Based on 
available data, EPA believes that sorbent injection (including ACI) has 
the potential to be a very effective technology for controlling Hg 
emissions in coal-fired plants, and some units using ACI for Hg control 
were among those selected for testing. EPA had no direct stack test 
results showing how effectively these ACI-equipped plants reduce their 
Hg emissions. The effectiveness of ACI is highly dependent upon the 
type of sorbent used (i.e., chemically treated versus conventional AC) 
and on the amount injected. Further, previous data-gathering efforts 
had shown that FFs are capable of providing highly effective control of 
certain species of Hg and, in some cases, as high or higher than that 
achieved by ACI (ACI is not always used to achieve maximum reductions 
in Hg but, rather, to achieve permit requirements). Thus, testing for 
Hg was included with the testing for the non-Hg metallic HAP.
    To be able to assess the impact of the standards (e.g., reduction 
in HAP emissions over current conditions), EPA selected at random 50 
units from the population of coal-fired units not selected in any of 
the above groups to test; specifics of the required testing may be 
found in Docket entry EPA-HQ-OAR-2009-0234-0062. We did not use the 
data gathered for the Utility Study because those data are outdated and 
lack sufficient detail. Thus, EPA believed that gathering these data 
was necessary to assess the emissions of this important source 
category.
    All IGCC units were also required to test; specifics of the 
required testing may be found in Docket entry EPA-HQ-OAR-2009-0234-
0062.
    EPA was able to identify the best performing coal-fired units for 
the three HAP surrogate groups but the data obtained in support of the 
Utility Study and the December 2000 Finding do not indicate that any 
oil-fired units control beyond some ESP use and the data do not show 
any correlation between the PM control at oil-fired units and emissions 
of non-Hg metallic HAP from those units. Further, no oil-fired EGU has 
been constructed in decades and no oil-fired EGU has a FGD system 
installed, eliminating the potential basis for the use of compliance 
with an SO 2 emissions limit that resulted in the 
installation of an FGD system as a basis for selecting best performers 
for the acid-gas HAP from such units. Thus, EPA had no basis for 
determining which oil-fired units may be the ``best performers.'' 
Therefore, EPA required that 66 units selected at random from the 
population of known oil-fired units test their stack emissions; 
specifics of the required testing may be found in Docket entry EPA-HQ-
OAR-2009-0234-0062.
    All petroleum coke-fired units identified were required to test; 
specifics of the required testing may be found in Docket entry EPA-HQ-
OAR-2009-0234-0062.
    Pursuant to CAA section 112(q)(3), CAA section 112 as in effect 
prior to the 1990 CAA amendments remains in effect for radionuclide 
emissions from coal-fired EGUs at the Administrator's discretion. For 
this reason, we did not require testing for radionuclides. We are also 
not proposing standards for radionuclides in this action.

F. What is the relationship between this proposed rule and other 
combustion rules?

1. CAA Section 111
    Revised NSPS for SO2, NOX, and PM were 
promulgated 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, we are proposing 
certain amendments to 40 CFR part 60, subpart Da. In developing this 
proposed rule, we considered the monitoring requirements, testing 
requirements, and recordkeeping requirements of the existing NSPS to 
avoid duplicating requirements to the extent possible.
2. CAA Section 112
    EPA has previously developed other non-EGU combustion-related 
NESHAP under CAA section 112(d) in addition to today's proposed rule 
for coal- and oil-fired EGUs. EPA signed final NESHAP for major and 
area source Boiler NESHAP on February 21, 2011 (to be

[[Page 25025]]

codified at 40 CFR part 63, subpart DDDDD and subpart JJJJJJ, 
respectively) and promulgated standards for stationary combustion 
turbines (CT) on March 5, 2004 (69 FR 10512; 40 CFR part 63 subpart 
YYYY). In addition to these two NESHAP, on February 21, 2011, EPA also 
signed final CAA section 129 standards for commercial and institutional 
solid waste incinerator (CISWI) units, including energy recovery units 
(to be codified at 40 CFR part 60, subparts CCCC (NSPS) and DDDD 
(emission guidelines) and a definition of non-hazardous secondary 
materials that are solid waste (Non-hazardous Solid Waste Definition 
Rule, to be codified at 40 CFR part 241, subpart B). EGUs and IB that 
combust fossil fuel and solid waste, as that term is defined by the 
Administrator pursuant to the Resource Conservation and Recovery Act 
(RCRA), will be subject to section 129 (e.g., CISWI energy recovery 
units), unless they meet one of the exemptions in CAA section 129(g). 
CAA section 129 standards are discussed in more detail below.
    The two IB NESHAP, CT NESHAP, and this proposed 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 (MWe or Btu/hr), the boiler/
furnace technology, or the portion of their electrical output (if any) 
for sale to any utility power distribution systems. See CAA section 
112(a)(8) (defining EGU) earlier.
    All of the MWe ratings quoted in the proposed rule are considered 
to be the original nameplate rated capacity of the unit. Cogeneration 
is defined as the simultaneous production of power (electricity) and 
another form of useful thermal energy (usually steam or hot water) from 
a single fuel-consuming process.
    The CT rule regulates HAP emissions from all simple-cycle and 
combined-cycle stationary CTs producing electricity or steam for any 
purpose. Because of their combustion technology, simple-cycle and 
combined-cycle stationary CTs (with the exception of IGCC units that 
burn gasified coal or petroleum coke syngas) are not considered EGUs 
for purposes of this proposed rule.
    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., no sales are made to the 
national electrical distribution grid) is considered an IB unit. A 
fossil fuel-fired combustion unit that serves a generator that produces 
electricity for sale is not considered to be an EGU under the proposed 
rule if the size of the combustion unit is less than or equal to 25 
MWe. Units under that size would be subject to one of appropriate 
Boiler NESHAP. Further, EPA interprets the CAA section 112(a)(8) 
definition such that a non-cogeneration unit must both have a 
combustion unit of more than 25 MWe and supply more than 25 MWe to any 
utility power distribution system for sale to be considered an EGU 
pursuant to this proposed rule so as to be consistent with the 
cogeneration definition in CAA section 112(a)(8). Such units that sell 
less than 25 MWe of their power generation to the grid would be subject 
to the appropriate Boiler NESHAP.
    As noted earlier, natural gas-fired EGU's were not included in the 
December 2000 listing. Thus, this proposed rule would not regulate a 
unit that otherwise meets the CAA section 112(a)(8) definition of an 
EGU but 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. Such units are considered to be natural gas-fired 
EGUs and would not be subject to this proposed rule.
    The CAA does not define the terms ``fossil fuel'' and ``fossil fuel 
fired;'' therefore, we are proposing definitions for both terms. The 
definition of ``fossil fuel fired'' will determine the applicability of 
the proposed rule to combustion units that sell electricity to the 
utility power distribution system. A number of units that may otherwise 
meet the CAA section 112(a)(8) EGU definition fire primarily non-fossil 
fuels (e.g., biomass). However, these units generally startup using 
either natural gas or oil and may use these fuels (or coal) during 
normal operation for flame stabilization. We have included a definition 
that will establish the scope of applicability based in part on the 
amount of fossil fuel combustion necessary to make a unit become 
``fossil fuel fired,'' and the units that combust primarily non-fossil 
fuel will be subject to this proposed rule should they fire more than 
that amount of coal or oil. Specifically, EPA is proposing that an EGU 
must be capable of combusting more than 73 MWe (250 MMBtu/hr) heat 
input \156\ (equivalent to 25 MWe output) of coal or oil to be 
considered an EGU subject to this proposed rule. To be ``capable of 
combusting'' coal or oil, a unit would need to have fossil fuels 
allowed in their permits and have the appropriate fuel handling 
facilities on-site (e.g., coal handling equipment, including for 
purposes of example, but not limited to, coal storage area, belts and 
conveyers, pulverizers, etc.; oil storage facilities). In addition, EPA 
is proposing that an EGU 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 to be considered a fossil fuel-fired EGU 
subject to this proposed rule. Units that do not meet these definitions 
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. 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. EPA solicits comment on the use of these definitions. 
Commenters suggesting alternate definitions (including thresholds) 
should provide detailed information in support of their comment (e.g., 
3- to 5-year average fossil fuel use under conditions of startup and 
flame stabilization).
---------------------------------------------------------------------------

    \156\ 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 IB).
---------------------------------------------------------------------------

    Also, a cogeneration facility that sells electricity to any utility 
power distribution system equal to more than one-third of their 
potential electric output capacity and more than 25 MWe is considered 
to be an EGU if it is fossil fuel fired as that term is defined above. 
For such units, EPA is proposing that the unit must be capable of 
combusting sufficient coal or oil to generate 25 MWe from the fossil 
fuel alone, and must provide for sale to any utility power distribution 
system electricity equal to

[[Page 25026]]

more than one-third of their potential electric output capacity and 
greater than 25 MWe electrical output. However, a cogeneration facility 
that meets the above definition of an EGU during any portion of a month 
would be subject to the proposed EGU rule for the succeeding 6 calendar 
months (combustion units that begin combusting solid waste must 
immediately comply with an applicable CAA section 129 standard (e.g., 
CISWI standards applicable to energy recovery units)).
    We recognize that different section 112 rules may impact a 
particular unit at different times. For example there will likely be 
some cogeneration units that are determined to be covered under the 
Boiler NESHAP. Such unit may make a decision to increase/decrease the 
proportion of production output being supplied 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 MWe). 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 proposed EGU NESHAP for the 6-month period 
after the unit meets the EGU definition. Assuming the unit 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. This approach is consistent with that taken on the CISWI 
rulemaking.
    EPA solicits comment on the extent to which this situation might 
occur and whether the 6-month period is appropriate. Given the 
differences between the rules, should EPA address reclassification of 
the sources between the rules, particularly with regard to initial and 
ongoing compliance requirements and schedules? (As noted above, EPA is 
proposing to consider as an EGU any cogeneration unit that meets the 
definition noted earlier during any month in a year.) We specifically 
solicit comments as to how to address sources that may meet the 
definition of an EGU for only parts of a year. We also solicit comment 
on whether we should include provisions similar to those included in 
the final CISWI rule to address units that combust different fuels at 
different times. See Final CISWI Rule, 40 CFR 60.2145, http://www.epa.gov/airquality/combustion/docs/20110221ciswi.pdf.
    Another situation 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, the emissions have to either be 
apportioned to the appropriate source or the more stringent emission 
limit must be met. Data needed to apportion emissions are not currently 
required by this proposed rule or the final Boiler NESHAP. Therefore, 
EPA is proposing that compliance with the more stringent emission limit 
be demonstrated.
    EPA solicits comment on the extent to which this situation might 
occur. Given potential differences between the rules, how should EPA 
address apportionment of the emissions to the individual sources with 
regard to initial and ongoing compliance requirements? EPA specifically 
requests comment on the appropriateness of a mass balance-type 
methodology to determine pollutant apportionment between sources both 
pre-APCD and post-APCD.
3. CAA Section 129
    Units that combust ``non-hazardous solid waste'' as defined by the 
Administrator under RCRA are regulated under the provisions of CAA 
section 129. On February 21, 2011, EPA signed the final Non-Hazardous 
Solid Waste Definition Rule. Any EGU that combusts any solid waste as 
defined in that final rule is a solid waste incineration unit subject 
to CAA section 129.
    In the Non-Hazardous Solid Waste Definition Rule, 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 the discarded coal refuse is processed in the 
same manner as currently mined coal refuse, the coal refuse would not 
be a solid waste and, therefore, the combustion of such material would 
not subject the unit to regulation under CAA section 129. By contrast, 
the unit would be subject to this rule if it meets the definition of 
EGU. If the unit combusts solid waste, it would be subject to emission 
standards under CAA section 129. See, e.g., CISWI rule. Coal refuse 
properly processed is a product fossil fuel (i.e., not a solid waste) 
if it is not a solid waste; thus, combustion units that otherwise meet 
the CAA section 112(a)(8) EGU definition that combust coal refuse that 
is product fuel not a solid waste are EGUs subject to this proposed 
rule. For this proposed rule, we assumed that all units that combust 
coal refuse and otherwise meet the definition of a coal-fired EGU 
combust newly mined coal refuse or coal refuse from legacy piles that 
has been processed such that it is not a solid waste. We request 
comment on this assumption and whether there are any units combusting 
coal refuse that is a solid waste such that the units would be solid 
waste incineration units instead of EGUs.
    Further, CAA section 129(g)(1)(B) exempts from regulation under CAA 
section 129

    ``* * * 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 
other forms of useful energy (such as heat) which are used for 
industrial, commercial, heating or cooling purposes * * *''

    Thus, qualifying small power production facilities and cogeneration 
facilities that burn a homogeneous waste would be exempt from 
regulation under CAA section 129. If the ``homogeneous waste'' material 
combusted is a fossil fuel, then the units that are exempt from 
regulation under CAA section 129 and that otherwise meet the definition 
of an EGU under CAA section 112(a)(8) would be covered under this 
proposed rule. For example, a unit that combusts only coal refuse that 
is a solid waste would be subject to this proposed rule if the unit met 
the definition of EGU and the coal refuse was determined to be a 
``homogenous waste'' as that term is defined in the final CAA section 
129 CISWI standards (the final rule was signed on February 21, 2011, 
but has not yet been published in the Federal Register).

G. What emission limitations and work practice standards must I meet?

    We are proposing the emission limitations presented in Tables 10 
and 11 of this preamble. Within the two major subcategories of ``coal'' 
and ``oil,'' emission limitations were developed for new and existing 
sources for five subcategories, two for coal-fired EGUs, one for coal- 
and solid oil-derived IGCC EGUs, and two for oil-fired EGUs, which we 
developed based on unit type.
    We are proposing that new or existing EGUs are ``coal-fired'' if 
they combust coal and meet the proposed definition of ``fossil fuel 
fired.'' We are proposing that an EGU is considered to be a ``coal-
fired unit designed for coal greater than or equal to 8,300 Btu/lb'' if 
the EGU: (1) Combusts coal; (2) meets the proposed definition of 
``fossil fuel fired;'' and (3) burns any coal in an EGU designed to 
burn a coal having a calorific value (moist, mineral matter-free basis) 
of

[[Page 25027]]

greater than or equal to 19,305 kilojoules per kilogram (kJ/kg) (8,300 
British thermal units per pound (Btu/lb)) in an EGU with a height-to-
depth ratio of less than 3.82. We are proposing that the EGU is 
considered to be a ``coal-fired unit designed for coal less than 8,300 
Btu/lb'' if the EGU: (1) Combusts coal; (2) meets the proposed 
definition of ``fossil fuel fired;'' and (3) burns any virgin coal in 
an EGU designed to burn a nonagglomerating fuel having a calorific 
value (moist, mineral matter-free basis) of less than 19,305 kJ/kg 
(8,300 Btu/lb) in an EGU with a height-to-depth ratio of 3.82 or 
greater.
    We are proposing that the EGU is considered to be an IGCC unit if 
the EGU: (1) Combusts gasified coal or solid oil-derived (e.g., 
petroleum coke); (2) meets the proposed definition of ``fossil fuel 
fired;'' and (3) is classified as an IGCC unit. We are not proposing to 
subcategorize IGCC EGUs based on the source of the syngas used (i.e., 
coal, petroleum coke). Based on information available to the Agency, 
although the fuel characteristics of coal and petcoke are quite 
different, the syngas products are very similar from both 
feedstocks.\157\
---------------------------------------------------------------------------

    \157\ U.S. Department of Energy, Wabash River Coal Gasification 
Repowering Project. Project Performance Summary; Clean Coal 
Technology Demonstration Program. DOE/FE-0448. July 2002.
---------------------------------------------------------------------------

    We are proposing that the EGU is considered to be ``liquid oil'' 
fired if the EGU burns liquid oil and meets the proposed definition of 
``fossil fuel fired.'' We are proposing that the EGU is considered to 
be ``solid oil-derived fuel-fired'' if the EGU burns any solid oil-
derived fuel (e.g., petroleum coke) and meets the proposed definition 
of ``fossil fuel fired.'' 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.

               Table 10--Emission Limitations for Coal-Fired and Solid Oil-Derived Fuel-Fired EGUS
----------------------------------------------------------------------------------------------------------------
             Subcategory              Total particulate matter     Hydrogen chloride             Mercury
----------------------------------------------------------------------------------------------------------------
Existing coal-fired unit designed     0.030 lb/MMBtu (0.30 lb/  0.0020 lb/MMBtu (0.020   1.0 lb/TBtu (0.0.008 lb/
 for coal [gteqt] 8,300 Btu/lb.        MWh).                     lb/MWh).                 GWh).
Existing coal-fired unit designed     0.030 lb/MMBtu (0.30 lb/  0.0020 lb/MMBtu (0.020   11.0 lb/TBtu (0.20 lb/
 for coal < 8,300 Btu/lb.              MWh).                     lb/MWh).                 GWh) 4.0 lb/TBtu *
                                                                                          (0.040 lb/GWh *).
Existing--IGCC......................  0.050 lb/MMBtu (0.30 lb/  0.00050 lb/MMBtu         3.0 lb/TBtu (0.020 lb/
                                       MWh).                     (0.0030 lb/MWh).         GWh).
Existing--Solid oil-derived.........  0.20 lb/MMBtu (2.0 lb/    0.0050 lb/MMBtu (0.080   0.20 lb/TBtu (0.0020 lb/
                                       MWh).                     lb/MWh).                 GWh).
New coal-fired unit designed for      0.050 lb/MWh............  0.30 lb/GWh............  0.000010 lb/GWh.
 coal [gteqt] 8,300 Btu/lb.
New coal-fired unit designed for      0.050 lb/MWh............  0.30 lb/GWh............  0.040 lb/GWh.
 coal < 8,300 Btu/lb.
New--IGCC...........................  0.050 lb/MWh *..........  0.30 lb/GWh *..........  0.000010 lb/GWh *.
New--Solid oil-derived..............  0.050 lb/MWh............  0.00030 lb/MWh.........  0.0020 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-electric output (gross).
lb/GWh = pounds pollutant per gigawatt-electric output (gross).
* Beyond-the-floor limit as discussed elsewhere.


                            Table 11--Emission Limitations for Liquid Oil-Fired EGUS
----------------------------------------------------------------------------------------------------------------
             Subcategory                 Total HAP metals *        Hydrogen chloride        Hydrogen fluoride
----------------------------------------------------------------------------------------------------------------
Existing--Liquid oil................  0.000030 lb/MMBtu.......  0.00030 lb/MMBtu.......  0.00020 lb/MMBtu.
                                      (0.00030 lb/MWh)........  (0.0030 lb/MWh)........  (0.0020 lb/MWh).
New--Liquid oil.....................  0.00040 lb/MWh..........  0.00050 lb/MWh.........  0.00050 lb/MWh.
----------------------------------------------------------------------------------------------------------------
* Includes Hg.

    Pursuant to CAA section 112(h), we are proposing a work practice 
standard for organic HAP, including emissions of dioxins and furans, 
from all subcategories of EGU. The work practice standard being 
proposed for these EGUs would require the implementation of an annual 
performance (compliance) test program as described elsewhere in this 
preamble. We are proposing work practice standards because the data 
confirm that the significant majority of the measured organic HAP 
emissions from EGUs are below the detection levels of the EPA test 
methods, and, as such, EPA considers it impracticable to reliably 
measure emissions from these units. As discussed later in this 
preamble, EPA believes the inaccuracy of a majority of measurements 
coupled with the extended sampling times used, fulfill the criteria for 
these HAP to be subject to a work practice standard under CAA section 
112(h).
    We are proposing a beyond-the-floor standard for Hg only for all 
existing coal-fired units designed for coal less than 8,300 Btu/lb 
based on the use of ACI for Hg control, as described elsewhere in this 
preamble. We are proposing a beyond-the-floor standard for all 
pollutants for new IGCC units based on the new-source limits for coal-
fired units designed for coal greater than or equal to 8,300 Btu/lb as 
described elsewhere in this preamble.
    As noted elsewhere in this preamble, we are proposing to use total 
PM as a surrogate for the non-Hg 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 liquid oil-fired EGUs, we 
are proposing total HAP metal, HCl, and HF emission limitations.

[[Page 25028]]

    In addition, we are proposing three alternative standards for 
certain subcategories: (1) SO2 (as an alternative equivalent 
to HCl for all subcategories with add-on FGD systems); (2) individual 
non-Hg metallic HAP (as an alternate to PM for all subcategories except 
liquid oil-fired); (3) total non-Hg metallic HAP (as an alternate to PM 
for all subcategories except liquid oil-fired); and (4) individual 
metallic HAP (as an alternate to total metal HAP) for the liquid oil-
fired subcategory. These alternative proposed standards are discussed 
elsewhere in this preamble.

H. What are the startup, shutdown, and malfunction (SSM) requirements?

    The DC Circuit Court vacated portions of two provisions in EPA's 
CAA section 112 regulations governing the emissions of HAP during 
periods of SSM. Sierra Club v. EPA, 551 F.3d 1019 (DC Cir. 2008), cert. 
denied, 130 S. Ct. 1735 (U.S. 2010). Specifically, the DC Circuit Court 
vacated the SSM exemption contained in 40 CFR 63.6(f)(1) and 40 CFR 
63.6(h)(1), that are part of a regulation, commonly referred to as the 
``General Provisions Rule,'' that EPA promulgated under CAA section 
112. When incorporated into CAA section 112(d) regulations for specific 
source categories, these two provisions exempt sources from the 
requirement to comply with the otherwise applicable CAA section 112(d) 
emission standard during periods of SSM.
    Consistent with Sierra Club, EPA is proposing standards in this 
rule that apply at all times. In proposing the standards in this rule, 
EPA has taken into account startup and shutdown periods and, for the 
reasons explained below, has not proposed different standards for those 
periods. The standards that we are proposing are 30 boiler operating 
day averages. EGUs, especially solid fuel-fired EGUs, do not normally 
startup and shutdown frequently and typically use cleaner fuels (e.g., 
natural gas or oil) during the startup period. Based on the data before 
the Agency, we are not establishing different emissions standards for 
startup and shutdown.
    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.
    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. EPA has determined that malfunctions 
should not be viewed as a distinct operating mode and, therefore, any 
emissions that occur at such times do not need to be factored into 
development of CAA section 112(d) standards, which, once promulgated, 
apply at all times. In Mossville Environmental Action Now v. EPA, 370 
F.3d 1232, 1242 (DC Cir. 2004), the DC Circuit Court upheld as 
reasonable standards that had factored in variability of emissions 
under all operating conditions. However, nothing in CAA section 112(d) 
or in case law requires that EPA anticipate and account for the 
innumerable types of potential malfunction events in setting emission 
standards. See, Weyerhaeuser v. Costle, 590 F.2d 1011, 1058 (DC 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.'')
    Further, it is reasonable to interpret CAA section 112(d) as not 
requiring EPA to account for malfunctions in setting emissions 
standards. For example, we note that CAA section 112 uses the concept 
of ``best performing'' sources in defining MACT, the level of 
stringency that major source standards must meet. Applying the concept 
of ``best performing'' to a source that is malfunctioning presents 
significant difficulties. The goal of best performing sources is to 
operate in such a way as to avoid malfunctions of their units.
    Moreover, even if malfunctions were considered a distinct operating 
mode, we believe it would be impracticable to take malfunctions into 
account in setting CAA section 112(d) standards for EGUs. As noted 
above, by definition, malfunctions are sudden and unexpected events and 
it would be difficult to set a standard that takes into account the 
myriad different types of malfunctions that can occur across all 
sources in the category. Moreover, malfunctions can vary in frequency, 
degree, and duration, further complicating standard setting.
    In the unlikely event that a source fails to comply with the 
applicable CAA section 112(d) standards as a result of a malfunction 
event, EPA would determine an appropriate response based on, among 
other things, the good faith efforts of the source to reduce the 
likelihood that malfunctions would occur, minimize emissions during 
malfunction periods, including preventative and corrective actions, as 
well as root cause analyses to ascertain and rectify excess emissions. 
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.'' See 40 CFR 63.2 (definition of 
malfunction).
    Finally, 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 (September 20, 1999); Policy 
on Excess Emissions During Startup, Shutdown, Maintenance, and 
Malfunctions (February 15, 1983)). EPA is, therefore, proposing 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 are proposing 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 section 
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

[[Page 25029]]

the narrow definition of malfunction in 40 CFR 63.2 (sudden, 
infrequent, not reasonably preventable and not caused by poor 
maintenance and/or careless operation). For example, to successfully 
assert the affirmative defense, 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 40 CFR 63.10000(b) 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 part 
22.77.

I. What are the testing requirements?

    We are proposing that the 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 concentration of a regulated pollutant under proposed 40 
CFR part 63, subpart UUUUU (e.g., Hg CEMS, SO2 CEMS, or HCl 
CEMS) or sorbent trap monitoring systems, the initial performance test 
would consist of all valid data recorded with the certified monitoring 
system in the first 30 operating days after the compliance date. For 
units using CEMS to measure a surrogate for a regulated pollutant 
(i.e., PM CEMS), initial stack testing of the surrogate and the 
regulated pollutant conducted during the same compliance test period 
and under the same process (e.g., fuel) and control device operating 
conditions would be required, and an operating limit would be 
established. Affected units would be required to 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 total PM emission limit, 
then you would conduct HAP metals and PM emissions testing during the 
same compliance test period and under the same process (e.g., fuel) and 
control device operating conditions initially and every 5 years using 
EPA Methods 29, 5, and 202. Continuous compliance would be determined 
using a PM CEMS with an operating limit established based on the 
filterable PM values measured using Method 5. If you elect to comply 
with the total HAP metals emission limit or the individual HAP metals 
emissions limits, then you would conduct total PM and HAP metals 
testing during the same compliance test period and under the same 
process (e.g., fuel) and control device operating conditions at least 
once every 5 years and, to demonstrate continuous compliance, you would 
conduct total or individual HAP metals emissions testing every 2 months 
(or every month if you have no PM control device) using EPA Method 29. 
Note that the filter temperature for each Method 29 or 5 emissions test 
is to be maintained at 160  14 [deg]C (320  25 
[deg]F) and that the material in Method 29 impingers is to be analyzed 
for metals content.
    (2) Coal-fired, IGCC, and solid oil-derived fuel-fired units would 
be required to use a Hg CEMS or sorbent trap monitoring system for 
continuous compliance using the continuous Hg monitoring provisions of 
proposed Appendix A to proposed 40 CFR part 63, subpart UUUUU. The 
initial performance test would consist of all valid data recorded with 
the certified Hg monitoring system in the first 30 boiler operating 
days after the compliance date.
    (3) For coal-fired and solid oil-derived fuel-fired units and new 
or reconstructed IGCC units that have SO2 emission controls 
and elect to use SO2 CEMS for continuous compliance, an 
initial stack test for SO2 would not be required. Instead 
the first 30 days of SO2 CEMS data would be used to 
determine initial compliance. For units with or without SO2 
or HCl emission controls that elect to use HCl CEMS, an initial stack 
test for HCl would not be required. Instead the first 30 days of HCl 
CEMS data would be used to determine initial compliance. For units 
without HCl CEMS and without SO2 or HCl emissions control 
devices, you would be required to conduct HCl emissions testing every 
month using EPA Method 26 if no entrained water droplets exist in the 
exhaust gas or Method 26A if entrained water droplets exist in the 
exhaust gas. For units without SO2 or HCl CEMS but with 
SO2 emissions control devices, you would conduct HCl testing 
at least every 2 months using EPA Method 26 or 26A. For units without 
SO2 or HCl CEMS and without SO2 emissions control 
devices, you would conduct HCl emissions testing every month using EPA 
Method 26A if entrained water droplets exist in the exhaust gas or 
Method 26A or 26 if no entrained water droplets exist in the exhaust 
gas.
    (4) For all required performance stack tests, you would conduct 
concurrent oxygen (O2) or carbon dioxide (CO2) 
emission testing using EPA Method 3A and then, use an appropriate 
equation, selected from among Equations 19-1 through 19-9 in EPA Method 
19 to convert measured pollutant concentrations to lb/MMBtu values. 
Multiply the lb/MMBtu value by one million to get the lb/TBtu value (if 
applicable).
    (5) For liquid oil-fired units, initial performance testing would 
be conducted as follows. For non-Hg HAP metals, use EPA Method 29. For 
Hg, conduct emissions testing using EPA Method 29 or Method 30B. For 
acid gases, conduct HCl and HF testing using EPA Methods 26A or 26. 
Conduct additional performance testing for Hg at least annually; 
conduct additional performance tests for HAP metals and acid gases 
every 2 months if the EGU has emission controls for metals or acid 
gases, and every month if the EGU does not have these controls.
    (6) For existing units that qualify as low emitting EGUs (LEEs), 
conduct subsequent performance tests for the LEE qualified pollutants 
every 5 years and perform fuel analysis monthly.
    Except for liquid oil-fired units, those EGUs with PM emissions 
control devices, without HCl CEMS but with HCl control devices, or for 
LEE, we are proposing that you monitor during initial performance 
testing specified operating parameters that you would use to 
demonstrate ongoing compliance. You would calculate the minimum (or 
maximum, depending on the parameter measured) hourly parameter values 
measured during each run of a 3-run performance test. The average of 
the three minimum (or maximum) values from the three runs for each 
applicable parameter would establish a site-specific operating limit. 
The applicable operating parameters for which operating limits would be 
required to be established are based on the emissions limits applicable 
to your unit as well as the types of add-on controls on the unit. The 
following is a summary of the operating limits that we are proposing to 
be established for the various types of the following units:

[[Page 25030]]

    (1) For units without wet or dry FGD scrubbers that must comply 
with an HCl emission limit, you must measure the average chlorine 
content level in the input fuel(s) during the HCl performance test. 
This is your maximum chlorine input operating limit.
    (2) For units with wet FGD scrubbers, you must measure pressure 
drop and liquid flow rate of the scrubber during the performance test, 
and determine the maximum value for each test run. The average of the 
minimum hourly value for the three test runs establishes your minimum 
site-specific pressure drop and liquid flow rate operating levels. If 
different average parameter levels are measured during the Hg and HCl 
tests, the highest of the average values becomes your site-specific 
operating limit. If you are complying with an HCl emission limit, you 
must measure pH of the scrubber effluent during the performance test 
for HCl and determine the minimum hourly value for each test run. The 
average of the three minimum hourly values from the three test runs 
establishes your minimum pH operating limit.
    (3) For units with dry scrubbers or DSI (including ACI), you would 
be required to measure the sorbent injection rate for each sorbent used 
during the performance tests for HCl and Hg and determine the minimum 
hourly rate of injected sorbent for each test run. The average of the 
three test run minimum values established during the performance tests 
would be your site-specific minimum sorbent injection rate operating 
limit. If different sorbents and/or injection rates are used during the 
Hg and HCl performance testing, the highest value for each sorbent 
becomes your site-specific operating limit for the respective HAP. If 
the same sorbent is used during the Hg and HCl performance testing, but 
at different injection rates, the highest average value for each 
sorbent becomes your site-specific operating limit. The type of sorbent 
used (e.g., conventional AC, brominated AC, trona, hydrated lime, 
sodium carbonate, etc.) must be specified.
    (4) For units with FFs in combination with wet scrubbers, you must 
measure the pH, pressure drop, and liquid flow rate of the wet scrubber 
during the performance test and calculate the minimum hourly value for 
each test run. The average of the minimum hourly values from the three 
test runs establishes your site-specific pH, pressure drop, and liquid 
flow rate operating limits for the wet scrubber.
    (5) For units with an ESP in combination with wet scrubbers, you 
must measure the pH, pressure drop, and liquid flow rate of the wet 
scrubber during the HCl performance test and you must measure the 
voltage and current of each ESP collection field during the Hg and PM 
performance test. You would then be required to calculate the minimum 
hourly value of these parameters for each of the three test runs. The 
average of the three minimum hourly values would establish your site-
specific minimum pH, pressure drop, and liquid flow rate operating 
limit for the wet scrubber and the minimum voltage and current 
operating limits for the ESP.
    (6) For liquid oil-fired or LEEs, you would be required to measure 
the Hg, Cl, and HAP metal content of the inlet fuel that was burned 
during the Hg, HCl and HF, and HAP metal emissions performance testing. 
The fuel content value for each of these compounds is your maximum fuel 
inlet operating limit for each of these compounds.
    (7) For units with FFs, you must measure the output of the bag leak 
detection system (BLDS) sensor (whether in terms of relative or 
absolute PM loading) during each Hg, PM, and metals performance test. 
You would then be required to calculate the minimum hourly value of 
this output for each test run. The average of the minimum hourly BLDS 
values would establish your site-specific maximum BLDS sensor output 
and current operating limit for the BLDS.
    (8) For units with an ESP, you must measure the voltage and current 
of each ESP collection field during each Hg, PM, and metals performance 
test. You would then be required to calculate the minimum hourly value 
of these parameters for each test run. The average of the three minimum 
hourly values would establish your site-specific minimum voltage and 
current operating limits for the ESP.
    (9) Note that you establish the minimum (or maximum) hourly average 
operating limits based on measurements done during performance testing; 
should you desire to have differing operating limits which correspond 
to other loads, you should conduct testing at those other loads to 
determine those other operating limits.
    Instead of operating limits for dioxins and furans and non-dioxin/
furan organic HAP, we are proposing that owners or operators of units 
submit documentation that a ``tune up'' meeting the requirements of the 
proposed rule was conducted. Such a ``tune-up'' would require the owner 
or operator of a unit to:
    (1) As applicable, inspect the burner, and clean or replace any 
components of the burner as necessary (you may delay the burner 
inspection until the next scheduled unit shutdown, but you must inspect 
each burner at least once every 18 months);
    (2) Inspect the flame pattern, as applicable, and make any 
adjustments to the burner necessary to optimize the flame pattern. The 
adjustment should be consistent with the manufacturer's specifications, 
if available;
    (3) Inspect the system controlling the air-to-fuel ratio, as 
applicable, and ensure that it is correctly calibrated and functioning 
properly;
    (4) Optimize total emissions of CO and NOX. This 
optimization should be consistent with the manufacturer's 
specifications, if available;
    (5) Measure the concentration in the effluent stream of CO and 
NOX in ppm, by volume, and oxygen in volume percent, before 
and after the 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); and
    (6) Maintain on-site and submit, if requested by the Administrator, 
an annual report containing:
    (i) The concentrations of CO and NOX in the effluent 
stream in ppm by volume, and oxygen in volume percent, measured before 
and after the adjustments of the EGU;
    (ii) A description of any corrective actions taken as a part of the 
combustion adjustment; and
    (iii) The type and amount of fuel used over the 12 months prior to 
the adjustment, but only if the unit was physically and legally capable 
of using more than one type of fuel during that period.
    Many, if not most, EGUs have planned annual outages, and the 
inspection and tune up procedure was designed to occur during this 
normal occurrence. Nonetheless, we are proposing a maximum period of up 
to 18 months between inspections and tune ups to account for those EGUs 
with unusual planned outage schedules. We seek comment on the 
appropriateness of this period.

J. What are the continuous compliance requirements?

1. Continuous Compliance Requirements
    To demonstrate continuous compliance with the emission limitations, 
we are proposing the following requirements:
    (1) For IGCC units or units combusting coal or solid oil-derived 
fuel and electing to use PM as a surrogate for non-Hg HAP metals, you 
would install, certify, and operate PM CEMS in

[[Page 25031]]

accordance with Performance Specification (PS) 11 in Appendix B to 40 
CFR part 60, and to perform periodic, on-going quality assurance (QA) 
testing of the CEMS according to QA Procedure 2 in Appendix F to 40 CFR 
part 60. An operating limit (PM concentration) would be set during 
performance testing for initial compliance; the hourly average PM 
concentrations would be averaged on a rolling 30 boiler operating day 
basis. Each 30 boiler operating day average would have to meet the PM 
operating limit.
    IGCC units or units combusting coal or solid oil-derived fuel and 
electing to comply with the total non-Hg HAP metals emissions limit, 
would demonstrate continuous compliance by conducting Method 29 testing 
every two months if PM controls are installed or every month if no PM 
controls are installed. As an option, PM CEMS could be used to 
demonstrate continuous compliance as described above. IGCC units or 
units combusting coal or solid oil-derived fuel and electing to comply 
with the individual non-Hg HAP metals emissions limits, would have the 
option to demonstrate continuous compliance only by conducting Method 
29; again, testing would be conducted every two months if PM controls 
are installed or every month if no PM controls are installed. IGCC 
units or units combusting coal or solid oil-derived fuel with PM 
controls but not using PM CEMS to demonstrate continuous compliance 
would also be required to conduct parameter monitoring and meet 
operating limits established during performance testing. Units using 
FFs would be required to install and operate BLDS. As mentioned 
earlier, the BLDS output would be required to be less than or 
equivalent with the average BLDS output determined during performance 
testing. Moreover, a source owner or operator would be required to 
operate the FFs such that the sum duration of alarms from the BLDS 
would not exceed 5 percent of the process operating time during any 6-
month period. Units using an ESP would be required to install and 
operate sensors to detect and measure current and voltage for each 
field in the ESP. As mentioned earlier, the current and voltage values 
for each field in the ESP would need to be greater than or equivalent 
with the maximum test run averages determined during performance 
testing.
    (2) For IGCC units or units combusting coal or solid oil-derived 
fuel, we are proposing that Hg CEMS or sorbent trap monitoring systems 
be installed, certified, maintained, operated, and quality-assured in 
accordance with proposed Appendix A to 40 CFR part 63, subpart UUUUU, 
and that Hg levels (averaged on a rolling 30 boiler operating day 
basis) be maintained at or below the applicable Hg emissions limit. 
Given that the proposed Appendix A QA procedures for Hg CEMS are based 
on a Hg emissions trading rule (CAMR), and this proposal is for a not-
to-exceed NESHAP, EPA solicits comments on whether these Hg CEMS QA 
procedures should be adjusted. Further, we are proposing that each pair 
of sorbent traps be used to collect Hg samples for no more than 14 
operating days, and that the traps be replaced in a timely manner to 
ensure that Hg emissions are sampled continuously. In requiring 
continuous Hg monitoring, we assumed that most, if not all, of the 
units that were subject to CAMR purchased Hg CEMS and/or sorbent trap 
systems prior to the rule vacatur, and that many of these monitoring 
systems are currently installed and in operation. The Agency's 
conclusion regarding Hg CEMS purchases and installation is based in 
part on the significant number of units (over 100) that voluntarily 
opted to submit Hg CEMS data for the 2010 ICR. We also considered the 
steps taken by the industry to prepare for CAMR, and the fact that many 
state regulations currently require the installation and operation of 
Hg CEMS in order to demonstrate compliance with various SIP and consent 
decrees.
    (3) For new or reconstructed IGCC units or coal-fired or solid oil-
derived fuel-fired units with SO2 emissions control devices, 
we are proposing two compliance options for acid gases. First, an 
SO2 or an HCl CEMS could be installed and certified. We are 
proposing that the SO2 monitor be certified and quality-
assured according to 40 CFR part 75 or PS 2 or 6 and Procedure 1 in 
Appendices B and F, respectively, of 40 CFR part 60. We believe this is 
reasonable, because nearly all utility units are subject to the ARP, 
and coal-fired ARP units already have certified SO2 monitors 
in place that meet Part 75 requirements. For HCl monitors, PS 15 or 6 
in Appendix B to 40 CFR part 60 would be used for certification and, 
tentatively, Procedure 1 of Appendix F to 40 CFR part 60 would be 
followed for on-going QA.
    Note that a PS specific to HCl CEMS has not been promulgated yet, 
but we expect to publish one prior to the compliance date of this 
proposed rule and to make it available to source owners and operators. 
In the meantime, the FTIR CEMS (PS 15) may be an appropriate choice for 
measuring continuous HCl concentrations. Hourly data from the 
SO2 or HCl monitor would be converted to the units of the 
emission standard and averaged on a rolling 30 boiler operating day 
basis. Each 30 boiler operating day average would have to meet the 
applicable SO2 or HCl limit.
    The second option that we are proposing would be for units without 
SO2 or HCl CEMS but with SO2 emissions control 
devices. For these units, parameter operating limits, established 
during performance testing, would be monitored continuously, along with 
the already-mentioned frequent (every 2 months) HCl emissions testing. 
For units with wet FGD scrubbers, we are proposing that you monitor 
pressure drop and liquid flow rate of the scrubber continuously and 
maintain 12-hour block averages at or above the operating limits 
established during the performance test. You must monitor the pH of the 
scrubber and maintain the 12-hour block average at or above the 
operating limit established during the performance test to demonstrate 
continuous compliance with the HCl emission limits.
    For units with dry scrubbers or DSI systems, we are proposing that 
you continuously monitor the sorbent injection rate and maintain it at 
or above the operating limits established during the performance tests.
    (4) For liquid oil-fired units, we are proposing to require testing 
as follows. HAP metals testing would be performed every other month if 
a unit has a non-Hg HAP metals control device, and every month if the 
unit does not have a non-Hg metals control device. We propose to 
require HCl and HF testing every other month if a unit has HCl and HF 
control devices, and monthly if the unit does not have these emissions 
controls.
    (5) For each unit using PM, HCl, SO2, or Hg CEMS for 
continuous compliance, we are proposing that you install, certify, 
maintain, operate and quality-assure the additional CEMS (e.g., CEMS 
that measure oxygen or CO2 concentration, stack gas flow 
rate, and moisture content) needed to convert pollutant concentrations 
to units of the emission standards or operating limits. Where 
appropriate, we have proposed that these additional CEMS may be 
certified and quality-assured according to 40 CFR part 75. Once again, 
we believe this is reasonable because almost all coal-fired utility 
units already have these monitors in place, under the ARP.
    (6) For limited-use liquid oil combustion units, we are proposing 
that those units be allowed to demonstrate compliance with the Hg 
emission limit, the HAP metals, or the HCl and HF emissions limits 
separately or in

[[Page 25032]]

combination based on fuel analysis rather than performance stack 
testing, upon request by you and approval by the Administrator. Such a 
request would require the owner/operator to follow the requirements in 
40 CFR 63.8(f), which presents the procedure for submitting a request 
to the Administrator to use alternative monitoring, and, among other 
things, explain why a unit should be considered for eligibility, 
including, but not limited to, use over the previous 5 years and 
projected use over the next 5 years. Approval from the Administrator 
would be required before you could use this alternative monitoring 
procedure. If approval were granted by the Administrator, we are 
proposing that you would maintain fuel records that demonstrate that 
you burned no new fuels or fuels from a new supplier such that the Hg, 
the non-Hg HAP metal, the fluorine, or the chlorine content of the 
inlet fuel was maintained at or below your maximum fuel Hg, non-Hg HAP 
metal, fluorine, or chlorine content operating limit set during the 
performance stack tests. If you plan to burn a new fuel, a fuel from a 
new mixture, or a new supplier's fuel that differs from what was burned 
during the initial performance tests, then you must recalculate the 
maximum Hg, HAP metal, fluorine, and/or chlorine input anticipated from 
the new fuels based on supplier data or own fuel analysis, using the 
methodology specified in Table 6 of this proposed rule. If the results 
of recalculating the inputs exceed the average content levels 
established during the initial test then, you must conduct a new 
performance test(s) to demonstrate continuous compliance with the 
applicable emission limit.
    (7) For existing LEEs, we are proposing that those units that 
qualify be allowed to demonstrate continuous compliance with the Hg 
emission limit, the non-Hg HAP metals, or the HCl emissions limits 
separately or in combination based on fuel analysis rather than 
performance stack testing. LEE would be those units where performance 
testing demonstrates that emissions are less than 50 percent of the PM 
or HCl emissions limits, less than 10 percent of the Hg emissions 
limits, or less than 22.0 pounds per year (lb/yr) of Hg. Note that for 
LEE emissions testing for total PM, total HAP metals, individual HAP 
metals, HCl, and HF, the required minimum sampling volumes shown in 
Table 2 or this proposed rule must be increased nominally by a factor 
of two. The LEE cutoff of 22.0 lb/yr represents about 5 percent of the 
nationwide Hg mass emissions from the coal-fired units represented in 
the 2010 ICR. Most of the units that emit less than 22.0 lb/yr would be 
smaller units with relatively low heat input capacities. The 22.0 lb/yr 
threshold was determined by summing the total Hg emissions from the 
1,091 units in operation and determining the 5th percentile of the 
total mass. The units were then ranked by their annual Hg mass 
emissions. At the point in the rankings where the cumulative mass was 
equivalent to the 5th percentile value calculated, the annual mass 
emissions of that unit (22.0 lb/yr) was selected as the threshold. Five 
percent of the total mass was chosen as a cut point because comments 
received on CAMR indicated that 5 percent of the total mass was a 
reasonable cut point. At this 5th percentile threshold, approximately 
394 smaller units out of the 1,091 total units would have the option of 
using this Hg monitoring methodology.
    Under the proposed alternative compliance option, you would 
maintain fuel records that demonstrate that you burned no new fuels or 
fuels from a new supplier such that the Hg, non-Hg HAP metal, or the 
chlorine content of the inlet fuel was maintained at or below your 
maximum fuel Hg, non-Hg HAP metal, fluorine, or chlorine content 
operating limit set during the performance stack tests. If you plan to 
burn a new fuel, a fuel from a new mixture, or a new supplier's fuel 
that differs from what was burned during the initial performance tests, 
then you must recalculate the maximum Hg, non-Hg HAP metal, and/or the 
maximum chlorine input anticipated from the new fuels based on supplier 
data or own fuel analysis, using the methodology specified in Table 6 
of this proposed rule. If the results of recalculating the inputs 
exceed the average content levels established during the initial test 
then, you must conduct a new performance test(s) to demonstrate 
continuous compliance with the applicable emission limit.
    (8) For all EGUs, we are proposing that you maintain daily records 
of fuel use that demonstrate that you have burned no materials that are 
considered solid waste.
    If an owner or operator would like to use a control device other 
than the ones specified in this section to comply with this proposed 
rule, the owner/operator should follow the requirements in 40 CFR 
63.8(f), which establishes the procedure for submitting a request to 
the Administrator to use alternative monitoring.
2. Streamlined Approach to Continuous Compliance
    EPA is proposing to simplify compliance with the proposed rule by 
harmonizing its monitoring and reporting requirements, to the extent 
possible, with those of 40 CFR part 75. With a few exceptions, the 
utility industry is already required to monitor and report hourly 
emissions data according to Part 75 under the Title IV ARP and other 
emissions trading programs. The Agency is, therefore, proposing Hg 
monitoring requirements that are consistent with Part 75 and similar to 
those that had been promulgated for the vacated CAMR regulation. We are 
proposing that hourly Hg emission data be reported to EPA 
electronically, on a quarterly basis. At this time, we are proposing 
not to apply the same electronic reporting for certification and QA 
test data from HCl or PM CEMS but are instead relying on the existing 
provisions in Parts 60 and 63.
    Our rationale for this is as follows. We considered two possible Hg 
monitoring and reporting options to demonstrate continuous compliance. 
The first option would be for Hg CEMS and sorbent trap systems to be 
certified and quality-assured according to PS 12A and 12B in Appendix B 
to 40 CFR part 60. Procedure 5 in Appendix F to Part 60 would be 
followed for on-going QA. Semiannual hard copy reporting of 
``deviations'' would be required, along with data assessment reports 
(DARs). Even though this option would not require electronic reporting 
of either hourly Hg emissions data or QA test results, it still would 
require affected sources to have a data handling system (DAHS) that: 
(1) Is programmed to capture data from the Hg CEMS; (2) uses the 
criteria in Appendix F to Part 60 to validate or invalidate the Hg 
data; (3) calculates hourly averages for Hg concentration and for the 
auxiliary parameters (e.g., flow rate, O2 or CO2 
concentration) that are needed to convert Hg concentrations to the 
units of the emission standard; (4) calculates 30 boiler operating day 
rolling average Hg emission rates; and (5) identifies any deviations 
that must be reported to the Agency.
    The second option would simply integrate Hg emissions data and QA 
test results into the existing Part 75-compliant DAHS that is installed 
at the vast majority of the coal-fired EGUs. We obtained feedback from 
several DAHS vendors indicating that the cost of modifying the existing 
Part 75 DAHS systems to accommodate hourly reporting of Hg CEMS and 
sorbent trap

[[Page 25033]]

data would be similar, and in some cases, less than the cost of the 
first option. Also, there would be little or no cost to industry for 
the flow rate, CO2, or O2, and moisture monitors 
needed to convert Hg concentration to the units of the standard, 
because, as previously noted, almost all of the EGUs already have these 
monitors in place. In view of these considerations, we have decided in 
favor of this second option for Hg.
    Requiring the reporting of hourly Hg emissions data from EGUs would 
be advantageous, both to EPA and industry. The DAHS could be automated 
to demonstrate compliance with the standard on a continuous basis. The 
data could then be submitted to the Agency electronically, thereby 
eliminating the need for the Agency to request additional information 
for compliance determinations and program implementation.
    Today's proposed rule would also require quarterly electronic 
reporting of hourly SO2 CEMS data, PM CEMS data, and HCl 
CEMS data (for sources electing to demonstrate continuous compliance 
using certified CEMS), as well as electronic summaries of emission test 
results (for sources demonstrating continuous compliance by periodic 
stack testing), and semiannual electronic ``deviation'' reports (for 
sources that monitor parameters or assess compliance in other ways). As 
discussed in detail in the paragraphs below, requiring electronic 
reporting in lieu of traditional hard copy reports would enable utility 
sources to demonstrate continuous compliance with the applicable 
emissions limitations of this proposed rule, using a process that is 
familiar to them and consistent with the procedures that they currently 
follow to comply with ARP and other mass-based emissions trading 
programs.
    Currently, utility sources that are subject to the ARP and other 
EPA emissions trading programs use the Emissions Collection and 
Monitoring Plan System (ECMPS) to process and evaluate continuous 
monitoring data and other information in an electronic format for 
submittal to the Agency. In addition to receiving hourly emissions 
data, this system supports the maintenance of an electronic 
``monitoring plan'' and is designed to receive the results of 
monitoring system certification test data and ongoing QA test data. 
Emissions data are submitted quarterly through ECMPS, and users are 
given feedback on the quality of their reports before the data are 
submitted. This allows them to make corrections or otherwise address 
issues with the reports prior to making their official submittals. 
Despite the stringency and thoroughness of the data validation checks 
performed by the ECMPS software, the implementation of this process has 
resulted in very few errant reports being submitted each quarter. This 
has saved both industry and the Agency countless hours of valuable 
time, which in years past, was spent troubleshooting errors in the 
quarterly reports. EPA is proposing to apply the same basic quarterly 
data collection process to Hg, HCl, and PM CEMS data, and to modify 
ECMPS to be able to accommodate summarized stack test data and 
semiannual deviation reports.
    The ECMPS process divides electronic data into three categories, 
the first of which is monitoring plan data. The electronic monitoring 
plan is maintained as a separate entity, and can be updated 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 that is 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 have established 
electronic monitoring plans that describe their required 
SO2, flow rate, CO2 or O2, and, in 
some cases, moisture monitoring systems. The ECMPS monitoring plan 
format could easily accommodate this same type of information for Hg, 
HCl, and PM 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. This includes data from linearity checks, relative 
accuracy test audits (RATAs), cycle time tests, 7-day calibration error 
tests, and a number of other QA tests that are required to validate the 
emissions data. The results of these tests can be submitted to EPA as 
soon as the results are received, 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 
are included in the quarterly electronic reports, along with the hourly 
emissions data.
    The ECMPS system is already 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 Part 75. EGUs routinely submit these data to EPA under the 
ARP and other emissions trading programs.
    To accommodate the certification and QA tests for Hg CEMS and 
sorbent trap monitoring systems, relatively few changes would have to 
be made to the structure and functionality of ECMPS, because most of 
the tests are the same ones that are required for other gas monitors. 
More substantive changes to the system would be required to receive and 
process the certification and QA tests required for HCl and PM CEMS, 
and to receive summarized stack test results, and the types of data 
provided in semiannual compliance reports; however, we believe these 
changes are implementable. Another modification that could be made to 
ECMPS would be to disable the Part 75 bias test (which is required for 
certain types of monitors under EPA's emissions trading programs) for 
Hg, HCl, and PM CEMS, if bias adjustment of the data from these 
monitors is believed to be unnecessary or inappropriate for compliance 
with the proposed rule. We are proposing to make this modification and 
solicit comment on it.
    The third type of data collected through ECMPS is the emissions 
data, which, as previously noted, is reported on a quarterly schedule. 
The reports must be submitted 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. Direct measurements made with CEMS, such as gas 
concentrations, are reported 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 Hg, HCl, and PM CEMS.
    The ECMPS reporting structure is quite flexible, which makes it 
useful for assessing compliance with various emission limits. The 
Derived Hourly Value (DHV) record provides the means whereby a wide 
variety of quantities that can be calculated from the hourly emissions 
data can be reported. For instance, if an emission limit is expressed 
in units of lb/MMBtu, the

[[Page 25034]]

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. ECMPS can 
also accommodate multiple DHV records for a given hour in which more 
than one derived value is required to be reported. Therefore, if hourly 
Hg, HCl, and PM concentration data are reported through ECMPS, 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), could be used to report 
hourly data in the units of the emission standards (e.g., lb/MMBtu, lb/
TBtu, lb/GWh, etc.).
    The ARP and other emissions trading programs that report emissions 
data to EPA using Part 75 are required to provide 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 may not 
be appropriate. Today's proposed rule would not require the use of 
missing data substitution for Hg monitoring systems. We intend to 
extend this concept to HCl and PM CEMS, if we receive data from those 
types of monitors. Hours when a monitoring system is out of service 
would simply be counted as hours of monitor down time, to be counted 
against the percent monitor availability. We solicit comment on this 
proposed approach.
    As previously stated, EPA is proposing to add Hg monitoring 
provisions as Appendix A to 40 CFR part 63, subpart UUUUU, and to 
require these provisions to be used to document continuous compliance 
with the proposed rule, for units that cannot qualify as LEEs. Proposed 
Appendix A would consolidate all of the Hg monitoring provisions in one 
place. Today's proposed rule would provide two basic Hg continuous 
monitoring options: Hg CEMS and sorbent trap monitoring systems.
    Proposed Appendix A would require the Hg CEMS and sorbent trap 
monitoring systems to be initially certified and then to undergo 
periodic QA testing. The certification tests required for the Hg CEMS 
would be 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 RATA. A bias test would not be 
required. The performance specifications for the required certification 
tests, which are summarized in Table A-1 of proposed Appendix A, would 
be the same as those that were published in support of CAMR. For 
ongoing QA of the Hg CEMS, proposed Appendix A would require daily 
calibrations, weekly single-point system integrity checks, quarterly 
linearity checks (or 3-level system integrity checks) and annual RATAs. 
These QA test requirements and the applicable performance criteria, 
which, once again, are the same as the ones we had published in support 
of CAMR, are summarized in Table A-3 in proposed Appendix A. For 
sorbent trap monitoring systems, a RATA would be required for initial 
certification, and annual RATAs would be required for ongoing QA. The 
performance specification for these RATAs would be the same as for the 
RATAs of the Hg CEMS. Bias adjustment of the measured Hg concentration 
data would not be required. However, for routine, day-to-day operation 
of the sorbent trap system, proposed Appendix A provides the owner or 
operator the option to follow the procedures and QA/QC criteria in PS 
12B in Appendix B to 40 CFR part 60. Performance Specification 12B is 
nearly identical to the vacated Appendix K to Part 75. The Part 75 
concepts of: (1) Determining the due dates for certain QA tests on the 
basis of ``QA operating quarters''; and (2) grace periods for certain 
QA tests, would apply to both Hg CEMS and sorbent trap monitoring 
systems.
    Mercury concentrations measured by Hg CEMS or sorbent trap systems 
would be used together with hourly flow rate, diluent gas, moisture, 
and electrical load data, to express the Hg emissions in units of the 
proposed rule, on an hourly basis (i.e., lb/TBtu or lb/GWh). Proposed 
section 6 of Appendix A provides the necessary equations for these unit 
conversions. These hourly values could then be ``rolled up'' within the 
DAHS into the proper 30 boiler operating day averaging period, to 
assess compliance. A report function could be added to ECMPS to show 
the results of these calculations, and to highlight any values in 
excess of the standard.
    The proposed rule would specify record keeping and reporting 
requirements for the two Hg monitoring methodologies. Essential 
information pertaining to each methodology would be represented in the 
electronic monitoring plan. Hourly Hg concentration data would be 
reported in all cases. However, for the sorbent trap option, a single 
Hg concentration value would be reported for extended periods of time, 
since a sorbent trap monitoring system does not provide hour-by-hour 
measurements of Hg concentration. The results of all required 
certification and QA tests would also be reported. Missing data 
substitution for Hg concentration would not be required for hours in 
which quality-assured data are not obtained. Special codes would be 
reported to identify these hours.
    Of all the types of NESHAP compliance data that could be brought 
into ECMPS (i.e., CEMS data, stack test summaries, and semiannual 
compliance reports), the easiest to implement would be the Hg 
monitoring data, because, as noted above, we had published specific Hg 
monitoring and reporting provisions in Part 75 prior to the vacatur of 
CAMR, and had made considerable progress in modifying ECMPS to receive 
these data. Today's proposed rule provides detailed regulatory language 
in proposed Appendix A to 40 CFR part 63, subpart UUUUU, pertaining to 
the monitoring of Hg emissions and reporting the data electronically.
    We are requesting comment on these proposed compliance approaches 
and on whether our proposed ``one stop shopping'' approach to reporting 
MACT compliance information electronically is desirable. In your 
comments, we ask you to consider the merits of requiring reporting of 
results from PM CEMS and HCl CEMS to ECMPS and consequent development 
of a monitoring and reporting scheme for these CEMS that is compatible 
with ECMPS. If you favor our proposed streamlined continuous compliance 
approach, we request input on how to make the reporting process user-
friendly and efficient. EPA believes that if the essential data that 
are reported under the Agency's emissions trading programs and the 
proposed rule are all sent to the same place, this could significantly 
reduce the burden on industry and bring about national consistency in 
assessing compliance.

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

    All new and existing sources would be required to comply with 
certain requirements of the General Provisions (40 CFR part 63, subpart 
A), which are identified in Table 10 of this proposed rule. The General 
Provisions include specific requirements for notifications, 
recordkeeping, and reporting.
    Each owner or operator would be required to submit a notification 
of compliance status report, as required by Sec.  63.9(h) of the 
General Provisions. This

[[Page 25035]]

proposed rule would require the owner or operator to include in the 
notification of compliance status report certifications of compliance 
with rule requirements.
    Except for units that use CEMS for continuous compliance, 
semiannual compliance reports, as required by Sec.  63.10(e)(3) of 
subpart A, would be required for semiannual reporting periods, 
indicating whether or not 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 previously discussed, we 
are proposing to use the ECMPS system to receive the essential 
information contained in these semiannual compliance reports 
electronically. For units using CEMS, quarterly electronic reporting of 
hourly Hg and associated (O2, CO2, flow rate, 
and/or moisture) monitoring data, as well as electronic reporting of 
monitoring plan data and certification and QA test results, would be 
required, also through ECMPS.
    This proposed rule would require records to demonstrate compliance 
with each emission limit and work practice standard. These 
recordkeeping requirements are specified directly in the General 
Provisions to 40 CFR part 63, and are identified in Table 9 of this 
proposed rule.
    Records of continuously monitored parameter data for a control 
device if a device is used to control the emissions or CEMS data would 
be required.
    We are proposing that you must keep the following records:
    (1) All reports and notifications submitted to comply with this 
proposed rule.
    (2) Continuous monitoring data as required in this proposed rule.
    (3) Each instance in which you did not meet each emission limit and 
each operating limit (i.e., deviations from this proposed rule).
    (4) Daily hours of operation by each source.
    (5) Total fuel use by each affected liquid oil-fired source 
electing to comply with an emission limit based on fuel analysis for 
each 30 boiler operating day period along with a description of the 
fuel, the total fuel usage amounts and units of measure, and 
information on the supplier and original source of the fuel.
    (6) Calculations and supporting information of chlorine fuel input, 
as required in this proposed rule, for each affected liquid oil-fired 
source with an applicable HCl emission limit.
    (7) Calculations and supporting information of Hg and HAP metal 
fuel input, as required in this proposed rule, for each affected source 
with an applicable Hg and HAP metal (or PM) emission limit.
    (8) A signed statement, as required in this proposed rule, 
indicating that you burned no new fuel type and no new fuel mixture or 
that the recalculation of chlorine input demonstrated that the new fuel 
or new mixture still meets chlorine fuel input levels, for each 
affected source with an applicable HCl emission limit.
    (9) A signed statement, as required in this proposed rule, 
indicating that you burned no new fuels and no new fuel mixture or that 
the recalculation of Hg and/or HAP metal fuel input demonstrated that 
the new fuel or new fuel mixture still meets the Hg and/or HAP metal 
fuel input levels, for each affected source with an applicable Hg and/
or HAP metal emission limit.
    (10) A copy of the results of all performance tests, fuel analyses, 
performance evaluations, or other compliance demonstrations conducted 
to demonstrate initial or continuous compliance with this proposed 
rule.
    (11) A copy of your site-specific monitoring plan developed for 
this proposed rule as specified in 63 CFR 63.8(e), if applicable.
    We are also proposing to require that you 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.
    (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.

L. Submission of Emissions Test Results to EPA

    EPA must have performance test data to conduct effective reviews of 
CAA sections 112 and 129 standards, as well as for many other purposes 
including compliance determinations, emission factor development, and 
annual emission rate determinations. In conducting these required 
reviews, EPA has found it ineffective and time consuming, not only for 
us, but also for regulatory agencies and source owners and operators, 
to locate, collect, and submit performance test data because of varied 
locations for data storage and varied data storage methods. In recent 
years, though, stack testing firms have typically collected performance 
test data in electronic format, making it possible to move to an 
electronic data submittal system that would increase the ease and 
efficiency of data submittal and improve data accessibility.
    Through this proposal, EPA is presenting a step to increase the 
ease and efficiency of data submittal and improve data accessibility. 
Specifically, EPA is proposing that owners and operators of EGUs submit 
electronic copies of required performance test reports to EPA's WebFIRE 
database. The WebFIRE database was constructed to store performance 
test data for use in developing emission factors. A description of the 
WebFIRE database is available at http://cfpub. epa. gov/oarweb/
index.cfm?action=fire. main.
    As proposed above, data entry would be through an electronic 
emissions test report structure called the Electronic Reporting Tool 
(ERT). The ERT would be able to transmit the electronic report through 
EPA's Central Data Exchange (CDX) network for storage in the WebFIRE 
database making submittal of data very straightforward and easy. A 
description of the ERT can be found at http://www.epa.gov/ttn/chief/ert/ert gov/ttn/chief/
ert/ert--tool. html.
    The proposal to submit performance test data electronically to EPA 
would 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 http://www.epa.gov/ttn/chief/ert/ert gov/ttn/chief/ert/ert--tool. html. 
We believe that industry would benefit from this proposed approach to 
electronic data submittal. Having these data, EPA would be able to 
develop improved emission factors, make fewer information requests, and 
promulgate better regulations.
    One major advantage of the proposed submittal of performance test 
data through the ERT is a standardized method to compile and store much 
of the documentation required to be reported by this rule. Another 
advantage is that the ERT clearly states what testing information would 
be required. Another important proposed benefit of submitting these 
data to EPA at the time the source test is conducted is that it should 
substantially reduce the effort involved in data collection activities 
in the future. When EPA has performance test data in hand, there will 
likely be fewer or less substantial data collection requests in 
conjunction with prospective required residual risk assessments or 
technology reviews. This

[[Page 25036]]

would result in a reduced burden on both affected facilities (in terms 
of reduced manpower to respond to data collection requests) and EPA (in 
terms of preparing and distributing data collection requests and 
assessing the results).
    State, local, and tribal agencies could also benefit from more 
streamlined and accurate review of electronic data submitted to them. 
The ERT would 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. Finally, 
another benefit of the proposed data submittal to WebFIRE 
electronically is that these data would 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, EPA would be able to ensure that 
emission factors, when updated, represent the most current range of 
operational practices. In summary, in addition to supporting regulation 
development, control strategy development, and other air pollution 
control activities, having an electronic database populated with 
performance test data would save industry, state, local, tribal 
agencies, and EPA significant time, money, and effort while also 
improving the quality of emission inventories and, as a result, air 
quality regulations. In this action, as previously stated, EPA is 
proposing a step to improve data accessibility. Specifically, we are 
proposing that you submit, to an EPA database, electronic copies of 
reports of certain performance tests required under the proposed rule 
through our ERT; however, we request comment on the feasibility of 
using a modified version of ECMPS, which the utility industry already 
is familiar with and uses for reporting under the Title IV ARP and 
other emissions trading programs, to provide this information.
    ECPMS could be modified to allow electronic submission of periodic 
data, including, but not limited to, 30 day averages of parametric 
data, 30 day average fuel content data, stack test results, and 
performance of tune up records. These data will need to be submitted 
and reviewed, and we believe electronic submission via a specific 
format already in use for other submissions eases understanding, 
affords transparency, ensures consistency, and saves time and money.
    We seek comment on alternatives to the use of a modified ECMPS for 
electronic data submission. Commenters should describe alternate means 
for supplying these data and information on associated reliability, the 
cost, the ease of implementation, and the transparency to the public of 
the information.

V. Rationale for This Proposed NESHAP

A. How did EPA determine which subcategories and sources would be 
regulated under this proposed NESHAP?

    As stated above, EPA added coal- and oil-fired EGUs to the CAA 
section 112(c) list on December 20, 2000. This proposed rule proposes 
standards for the subcategories of coal- and oil-fired EGUs as defined 
in this preamble. Sources in these subcategories may potentially 
include combustion units that are at times IB units or solid waste 
incineration units subject to other standards under CAA section 112 or 
to standards under CAA section 129. We request comment on whether the 
proposed rule should address how sources that change fuel input (e.g., 
burn solid waste or biomass), or otherwise take action that would 
change the source's applicability (e.g., stop or start selling 
electricity to the utility power distribution system), must demonstrate 
continuous compliance with all applicable standards. Note that units 
subject to another CAA section 112 standard or to solid waste 
incineration unit standards established under CAA section 129 are not 
subject to this proposed rule during the period of time they are 
subject to the other CAA section 112 or 129 standards.
    The scope of the EGU source category is limited to coal- and oil-
fired units meeting the CAA section 112(a)(8) definition and the 
proposed definition of ``fossil fuel fired'' discussed above.
    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. For 
example, differences between given types of units can lead to 
corresponding differences in the nature of emissions and the technical 
feasibility of applying emission control techniques. In the December 
2000 listing, EPA initially established and listed two subcategories of 
fossil fuel-fired EGUs: Coal-fired and oil-fired. The design, 
operating, and emissions information that EPA has reviewed indicates 
that there are significant design and operational differences in unit 
design that distinguish different types of EGUs within these two 
subcategories, and, because of these differences, we have proposed to 
establish two subcategories for coal-fired EGUs, two subcategories for 
oil-fired EGUs, and an IGCC subcategory for gasified coal and solid 
oil-derived fuel (e.g., petroleum coke), as stated above and discussed 
further below.
    EGU systems are designed for specific fuel types and will encounter 
problems if a fuel with characteristics other than those originally 
specified is fired. Changes to the fuel type would generally require 
extensive changes to the fuel handling and feeding system (e.g., liquid 
oil-fired EGUs cannot fire solid fuel without extensive modification). 
Additionally, the burners and combustion chamber would need to be 
redesigned and modified to handle different fuel types and account for 
increases or decreases in the fuel volume. In some cases, the changes 
may reduce the capacity and efficiency of the EGU. An additional effect 
of these changes would be extensive retrofitting needed to operate 
using a different fuel. These effects must be considered whether one is 
discussing two fuel types (e.g., coal vs. oil) or two ranks or forms of 
fuel within a given fuel type (e.g., gasified vs. solid coal or solid 
oil-derived fuel).
    The design of the EGU, which is dependent in part on the type of 
fuel being burned, impacts the degree of combustion, and may impact the 
level and kind of HAP emissions. EGUs emit a number of different types 
of HAP emissions. Organic HAP are formed from incomplete combustion and 
are primarily influenced by the design and operation of the unit. The 
degree of combustion may be greatly influenced by three general 
factors: Time, turbulence, and temperature. On the other hand, the 
amount of fuel-borne HAP (non-Hg metals, Hg, and acid gases) is 
primarily dependent upon the composition of the fuel. These fuel-borne 
HAP emissions generally can be controlled by either changing the fuel 
property before combustion or by removing the HAP from the flue gas 
after combustion.
    We first examined the HAP emissions results to determine if 
subcategorization by unit design type was warranted. Normally, any 
basis for subcategorizing (e.g., type of unit) must be related to an 
effect on emissions, rather than some difference which does not affect 
emissions performance. We concluded that the data were sufficient for 
one or

[[Page 25037]]

more HAP for determining that a distinguishable difference in 
performance exists based on the following five unit design types: coal-
fired units designed to burn coal with greater than or equal to 8,300 
Btu/lb (for Hg emissions only); coal-fired units designed to burn coal 
with less than 8,300 Btu/lb (for Hg emissions only); IGCC units; liquid 
oil units; and solid oil-derived units. For other types of units noted 
above (e.g., FBC, stoker, wall-fired, tangential (T)-fired), there was 
no significant difference in emissions that would justify 
subcategorization. Because in the five cases different types of units 
have different emission characteristics for one or more HAP, we have 
determined that these types of units should be subcategorized. 
Accordingly, we propose to subcategorize EGUs based on the five unit 
types.
    For Hg emissions from coal-fired units, we have determined that 
different emission limits for the two subcategories are warranted. 
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.
    For all HAP emissions from oil-fired units, we have determined that 
two subcategories are warranted. EGUs designed to burn a solid fuel 
(e.g., petroleum coke) derived from the refining of petroleum (oil) are 
of a different design, and have different emissions, than those 
designed to burn liquid oil. In addition, EGUs designed to burn liquid 
oil cannot, in fact, accommodate the solid fuel derived from the 
refining of oil. Thus, we are proposing to subcategorize oil-fired EGUs 
into two subcategories based on the type of units designed to burn oil 
in its different physical states.
    EGUs employing IGCC technology combust a synthetic gas derived from 
solid coal or solid oil-derived fuel. No solid fuel is directly 
combusted in the unit during operation (although a coal- or solid oil-
derived fuel is fired), and both the process and the emissions from 
IGCC units are different from units that combust solid coal or 
petroleum coke. Thus, we are proposing to subcategorize IGCC units as a 
distinct type of EGU for this proposed rule. EPA solicits comment on 
these subcategorization approaches.
    Additional subcategories have been evaluated, including those 
suggested by the SERs serving on the SBAR established under the SBREFA. 
These suggestions include subcategorization of lignite coal vs. other 
coal ranks; subcategorization of Fort Union lignite coal vs. Gulf Coast 
lignite coal vs. other coal ranks; subcategorization by EGU size (i.e., 
MWe); subcategorization of base load vs. peaking units (e.g., low 
capacity utilization units); subcategorization of wall-fired vs. T-
fired units; and subcategorization of small, non-profit-owned units vs. 
other units.
    EPA has reviewed the available data and does not believe that these 
suggested approaches merit subcategorization. For example, there are 
both large and small units among the EGUs comprising the top performing 
12 percent of sources and small entities may own minor portions of 
large EGUs and/or individual EGUs themselves. In addition, because the 
proposed format of the standards is lb/MMBtu (or TBtu for Hg), the size 
should only affect the rate at which a unit generates electricity and, 
with a lower electricity generation rate, there is less fuel 
consumption and, therefore, less emissions of fuel-borne HAP (i.e., 
acid gas and metal HAP). Further, with the exception of IGCC and as 
noted elsewhere regarding boiler height-to-depth ratio, there is no 
indication that EGU type (e.g., wall-fired, T-fired, FBC, stoker-
fired), has any impact on HAP emission levels as all of these types are 
within the top performing 12 percent of sources. There is also little 
indication that operating load has any significant impact on HAP 
emissions or on the type of control demonstrated on the unit.
    EPA solicits comment on whether we should further subcategorize the 
source category. In commenting, commenters should provide a definition 
or threshold that would distinguish the proposed subcategory from the 
remainder of the EGU population and, to support this distinction, an 
estimate of how many EGUs would be impacted by the subcategorization 
approach, the amount of time such impacted units operate, the extent to 
which such impacted units would move out of and back into the 
subcategory in a given year (or other period of time), and any other 
information the commenter believes is pertinent. For example, if a 
commenter were to suggest subcategorizing low capacity factor or 
peaking units from the remainder of the EGU population, in addition to 
the suggested threshold capacity factor, information on the number of 
such units that would be impacted, the amount of time such units are 
running (capacity utilization), the extent to which such units are low 
capacity factor units in a given year vs. operating at a higher 
capacity factor, and data from the units when operating both as peaking 
units and as baseload units (among other information) would need to be 
provided to support the comment. Commenters should further explain how 
their suggested subcategorizations constitute a ``size,'' ``type,'' or 
``class,'' as those terms are used in CAA section 112(d)(1).

B. How did EPA select the format for this proposed rule?

    This proposed rule includes numerical emission limitations for PM, 
Hg, and HCl (as well as for other alternate constituents or groups). 
Numerical emission limitations provide flexibility for the regulated 
community, because they allow a regulated source to choose any control 
technology, approach, or technique to meet the emission limitations, 
rather than requiring each unit to use a prescribed control method that 
may not be appropriate in each case.
    We are proposing numerical emission rate limitations as a mass of 
pollutant emitted per heat energy input to the EGU for the fuel-borne 
HAP for existing sources. The most typical units for the limitations 
are lb/MMBtu of heat input (or, in the case of Hg, lb/TBtu). The mass 
per heat input units are consistent with other Federal and many state 
EGU regulations and allows easy comparison between such requirements. 
Additionally, this proposed rule contains an option to monitor inlet 
chlorine, fluorine, non-Hg metal, and Hg content in the liquid oil to 
meet outlet emission rate limitations. This is reasonable because oil-
fired units may choose to remove these fuel-borne HAP from the oil 
before combustion in lieu of installing air pollution control devices. 
This option can only be done on a mass basis by liquid oil-fired EGUs. 
We request comment on the viability of this approach for IGCC units.

[[Page 25038]]

    We are proposing numerical emission rate limitations as a mass of 
pollutant emitted per megawatt- or gigawatt-hour (MWh or GWh) gross 
output from the EGU for the fuel-borne HAP for new sources and as an 
alternate format for existing sources. An outlet numerical emission 
limit is also consistent with the format of other regulations (e.g., 
the EGU NSPS, 40 CFR part 60, subpart Da).
    EGUs can emit a wide variety of compounds, depending on the fuel 
burned. Because of the large number of HAP potentially present and the 
disparity in the quantity and quality of the emissions information 
available, EPA grouped the HAP into five categories based on available 
information about the pollutants and on experiences gained on other 
NESHAP: Hg, non-Hg metallic HAP, inorganic (i.e., acid gas) HAP, non-
dioxin/furan organic HAP, and dioxin/furan organic HAP. The pollutants 
within each group have similar characteristics and can be controlled 
with the same techniques. For example, non-Hg metallic HAP can be 
controlled with PM controls. We chose to look at Hg separately from 
other metallic HAP due to its different chemical characteristics and 
its different control technology feasibility.
    Next, EPA identified compounds that could be used as surrogates for 
all the compounds in each pollutant category. Existing technologies 
that have been installed to control emissions of other (e.g., criteria) 
pollutants are expected to provide coincidental or ``co-benefit'' 
control of some of the HAP. For example, technologies for PM control 
(e.g., ESP, FF) can effectively remove Hg that is bound to particulate 
such as injected sorbents, unburned carbon, or other fly ash particles. 
Similarly, PM control technologies are effective at reducing emissions 
of the non-Hg metal HAP that are present in the fly ash as solid 
particulate. Flue gas desulfurization technologies typically remove 
SO2 using acid-base neutralization reactions (usually via 
contact with alkaline solids or slurries). This approach is also 
effective for other acid gases as well, including the acid gas HAP 
(HCl, HF, Cl2, and HCN).
    EGUs routinely measure operating parameters (flow rates, 
temperatures, pH, pressure drop, etc.) and flue gas composition for 
process control and monitoring and for emission compliance and 
verification. Some of these routinely or more easily-measured 
parameters or components may serve as surrogates or indicators of the 
level of control of one or more of the HAP that may not be easily or 
routinely measured or monitored. The use of more easily-measured 
components or process conditions as surrogates or predictors of HAP 
emissions can greatly simplify monitoring requirements under this 
proposed rule and, in some cases, provide more reliable results.
    In order to evaluate potential surrogacy relationships, the EPA 
Office of Research and Development (ORD), in collaboration with OAR, 
conducted a series of tests in the Agency's Multipollutant Control 
Research Facility (MPCRF), a pilot-scale combustion and control 
technology research facility located at EPA's Research Triangle Park 
campus in North Carolina. The combustor is rated at 4 MMBtu/hr 
(approximately 1.2 megawatt-thermal (MWt)). It is capable of 
firing all ranks of pulverized coal, natural gas, and fuel oil. The 
facility is equipped with low NOX burners and an SCR unit 
for NOX control. The system can be configured to allow the 
flue gas to flow through either an ESP or a FF for PM control. The 
facility also uses a wet lime-based FGD scrubber for control of 
SO2 emissions. The system is well equipped with CEMS for on-
line measurement of O2, CO2, NOX 
(nitrogen oxide, NO, and nitrogen dioxide, NO2), 
SO2, CO, Hg, and THC. There are multiple sampling ports 
throughout the flue gas flow path. The facility is designed for ease of 
modification so that various control technologies and configurations 
can be tested. The facility has a series of heat exchangers to remove 
heat such that the flow path of the flue gas has a similar time-
temperature profile to that seen in a typical full-scale coal-fired 
EGU.
    Eleven independent tests were performed in the MPCRF in order to 
examine potential surrogacy relationships. Three types of coal (eastern 
bituminous, subbituminous, and Gulf Coast lignite) were tested. The PM 
control was also varied; in some tests, the ESP was used whereas the FF 
was used in others. Three potential surrogacy relationships were 
examined during the testing program. The potential for use of PM 
control as a surrogate for the control of the non-Hg metal HAP (Be, As, 
Cd, Co, Cr, Mn, Ni, Pb, Sb, and Se) was examined. The potential for use 
of HCl or SO2 control as a surrogate for other acid gases 
(HCl, HF, Cl2) was studied. In addition, several potential 
surrogate relationships were examined for the non-dioxin/furan organic 
HAP. No surrogate studies were conducted for Hg; we have not identified 
any surrogates for Hg and, thus, are regulating Hg directly. No 
surrogacy studies were conducted for dioxin/furan organic HAP because 
we believed the S:Cl ratio in the flue gas would be greater than 1.0, 
meaning that the formation of dioxins/furans would be inhibited. 
Moreover, it was anticipated that levels of these compounds would be 
very low, and, as mentioned earlier in the preamble, the approved 2010 
ICR sampling methods for dioxin/furan organic HAP required 8-hour 
sampling periods; such a long sampling period was not practical in our 
pilot system and would not be practical on a continuous basis.
    The results of the program indicated that the control of all non-Hg 
metal HAP (except Se) was consistently similar to the control of the 
bulk total PM (PMtotal). The average PMtotal 
control during the tests was 99.5 percent. All of the non-Hg metal HAP 
were controlled along with the PMtotal at levels greater 
than 95 percent for measurements taken for particulate control using 
both the ESP and the FF. Average control for the test series for each 
of the metals was (for all coals and all configurations): Sb--95.3 
percent; As--98.0 percent; Be--98.5 percent; Cd--98.7 percent; Cr--98.0 
percent; Co--99.3 percent; Pb--99.2 percent; Mn--99.5 percent; and Ni--
97.6 percent.
    The results for Se control were less consistent. When subbituminous 
coal was fired, the control of Se was consistently very good (average 
98.9 percent), regardless of the PM control device being used. When 
using the FF as the primary PM control device, the Se control was 
consistently very good (average 99.2 percent) regardless of the coal 
being fired. Control of Se when the ESP was the primary PM control 
device was variable. When subbituminous coal was fired, the control of 
Se through the ESP was greater than 99 percent. When lignite was fired, 
the control through the ESP was about 80 percent. However, when the 
eastern bituminous coal was fired, the Se control through the ESP 
ranged from zero to 73 percent.
    The variability in the performance of Se control with coal rank and 
PM control device can be explained by the known behavior and chemistry 
of Se in the combustion and flue gas environments. Selenium is a 
metalloid that sits just below sulfur on the periodic table and is, 
chemically, very similar to sulfur. In the high temperature combustion 
environment, Se is likely to be present as gas phase SeO2 
(as, similarly, sulfur is likely to be present as gaseous 
SO2). Much like SO2, SeO2 is a weak 
acid gas. The testing in the pilot-scale combustion facility showed 
that Se in the flue gas entering the PM control device tended to be 
predominantly in the gas phase (55 to 90 percent) when firing eastern 
bituminous coal and predominantly in the solid phase when firing 
subbituminous coal (greater than 95

[[Page 25039]]

percent) and Gulf Coast lignite (80 percent). This is explained by the 
large difference in calcium (Ca) content of those fuels. The ash from 
the bituminous coal contained 1.4 weight percent Ca, whereas the ashes 
from the subbituminous coal and Gulf Coast lignite contained Ca at 10.0 
weight percent and 9.0 weight percent, respectively. The alkaline Ca in 
the fly ash effectively neutralized the SeO2 acid gas, 
forming a particulate that is easily removed in the PM control device. 
The bituminous fuel contained insufficient free Ca to completely 
neutralize the SeO2 and the much increased levels of 
SO2 in that flue gas. The good performance through the FF 
(regardless of the fuel being fired) can be attributed to the increased 
contact between the gas stream and the filter cake on the FF. This 
allows more of the SeO2 to adsorb or condense on fly ash 
particles--either alkaline particles or unburned carbon. Because 
SeO2 behaves very similarly to its sulfur analog, 
SO2, it can be expected to also be removed effectively in 
standard FGD technologies (wet scrubbers, dry scrubbers, DSI, etc.). 
Therefore, Se will either fall in to the category of ``non-Hg metal 
HAP'' and be effectively removed in a PM control device, or it will 
fall into the category of ``acid gas HAP'' as gaseous SeO2 
and be effectively removed using FGD technologies.
    Two of the 11 tests were specifically designated for testing of 
surrogacy relationships relating to the acid gas HAP. Eastern 
bituminous coal was fired and duct samples were taken upstream and 
downstream of the lime-based wet FGD scrubber. Those tests showed, as 
expected, very high levels of control for HCl (greater than 99.9 
percent control). The control of HF was greater than 92 percent for the 
first run and greater than 76 percent for the second run. The control 
of Cl2 was greater than 76 percent for the first run and 
greater than 92 percent for the second run. (Note that both of these 
control efficiencies were likely much higher than the reported values 
because the outlet measurements were below the MDL for both HF and 
Cl2. The control efficiencies were calculated using the MDL 
value.) The control efficiency for SO2 for the runs was 
greater than 98 percent.
    Tests were also conducted to examine potential surrogacy 
relationships for the non-dioxin/furan organic HAP. The amounts of Hg, 
non-Hg metals, HCl, HF, and Cl2 in the flue gas are directly 
related to the amounts of Hg, non-Hg metals, chlorine, and fluorine in 
the coal. Control of these components generally requires downstream 
control technology. However, the presence of the organics in the flue 
gas is not related to the composition of the fuel but rather they are a 
result of incomplete or poor combustion. Control of the organics is 
often achieved by improving combustion conditions to minimize formation 
or to maximize destruction of the organics in the combustion 
environment.
    During the pilot-scale tests, sampling was conducted for semi-
volatile and volatile organic HAP and aldehydes. On-line monitors also 
collected data on THC, CO, O2, and other processing 
conditions. Total hydrocarbons and CO have been used previously as 
surrogates for the presence of non-dioxin/furan organics. Carbon 
monoxide has often been used as an indicator of combustion conditions. 
Under conditions of ideal combustion, a carbon-based or hydrocarbon 
fuel will completely oxidize to produce only CO2 and water. 
Under conditions of incomplete or non-ideal combustion, a greater 
amount of CO will be formed.
    With complex carbon-based fuels, combustion is rarely ideal and 
some CO and concomitant organic compounds are expected to be formed. 
Because CO and organics are both products of poor combustion, it is 
logical to expect that limiting the concentration of CO would also 
limit the production of organics. However, it is very difficult to 
develop direct correlations between the average concentration of CO and 
the amount of organics produced during the prescribed sampling period 
in the MPCRF (which was 4 hours for the pilot-scale tests described 
here). This is especially true for low values of CO as one would expect 
corresponding low quantities of organics to be produced. Samples of 
coal combustion flue gas have mostly shown very low quantities of the 
organic compounds of interest. Some of the flue gas organics may also 
be destroyed in the high temperature post combustion zone (whereas the 
CO would remain stable). Semi-volatile organics may also condense on PM 
and be removed in the PM control device.
    The average CO from the pilot-scale tests ranged from 23 to 137 ppm 
for the bituminous coals tests, from 43 to 48 ppm for the subbituminous 
coal tests and from 93 to 129 ppm for the Gulf Coast lignite tests. 
However, it was difficult to correlate that concentration to the 
quantity of organics produced for several reasons. The most difficult 
problems are associated with the large number of potential organics 
that can be produced (both those on the HAP list and those that are not 
on the HAP list). This is further complicated by the organic compounds 
tending to be at or below the MDL in coal combustion flue gas samples. 
Further, there are complications associated with the CO concentration 
values. Some of the runs with very similar average concentrations of CO 
had very different maximum concentrations of CO (i.e., some of the runs 
had much more stable emissions of CO whereas others had some 
excursions, or ``spikes,'' in CO concentration). For example, one of 
the bituminous runs had an average CO concentration of 69 ppm but a 
maximum concentration of 1,260 ppm (due to a single ``spike'' of CO 
during a short upset). Comparatively, another bituminous run had a 
higher average CO concentration at 137 ppm but a much lower maximum CO 
value at 360 ppm.
    In the pilot tests, the THC measurement was inadequate as the 
detection limit of the instrument was much too high to detect changes 
in the very low concentrations of hydrocarbons in the flue gas.
    Based on the testing described above and the emissions data 
received under the 2010 ICR, we are proposing surrogate standards for 
the non-Hg metallic HAP and the non-metallic inorganic (acid gas) HAP. 
For the non-Hg metallic HAP, we chose to use PM as a surrogate. Most, 
if not all, non-Hg metallic HAP emitted from combustion sources will 
appear on the flue gas fly-ash. Therefore, the same control techniques 
that would be used to control the fly-ash PM will control non-Hg 
metallic HAP. PM was also chosen instead of specific metallic HAP 
because all fuels do not emit the same type and amount of metallic HAP 
but most generally emit PM that includes some amount and combination of 
all the metallic HAP. The use of PM as a surrogate will also eliminate 
the cost of performance testing to comply with numerous standards for 
individual non-Hg metals. Because non-Hg metallic HAP may 
preferentially partition to the small size particles (i.e., fine 
particle enrichment), we considered using PM2.5 as the 
surrogate, but we determined that total PM (filterable (i.e., 
PM2.5) plus condensable) was the more appropriate surrogate 
for two reasons. The test method (201A) for measuring PM2.5 
is only applicable for use in exhaust stacks without entrained water 
droplets. Therefore, the test method for measuring PM2.5 is 
not applicable for units equipped with wet scrubbers which are in use 
at many EGUs today and may be necessary at some additional units to 
achieve the proposed HCl emission limitations. Thus, we are proposing 
to use total PM, instead of PM2.5, as the surrogate for non-
Hg metals. However, as discussed elsewhere, we are also proposing

[[Page 25040]]

alternative individual non-Hg metallic HAP emission limitations as well 
as total non-Hg metallic HAP emission limitations for all subcategories 
(total metal HAP emission limitation for the liquid oil-fired 
subcategory).
    For non-metallic inorganic (acid gas) HAP, EPA is proposing setting 
an HCl standard and using HCl as a surrogate for the other non-metallic 
inorganic HAP for all subcategories except the liquid oil-fired 
subcategory. The emissions test information available to EPA indicate 
that the primary non-metallic inorganic HAP emitted from EGUs are acid 
gases, with HCl present in the largest amounts. Other inorganic 
compounds emitted are found in smaller quantities. As discussed 
earlier, control technologies that reduce HCl indiscriminately control 
other inorganic compounds such as Cl2 and other acid gases 
(e.g., HF, HCN, SeO2). Thus, the best controls for HCl are 
also the best controls for other inorganic acid gas HAP. Therefore, HCl 
is a good surrogate for inorganic HAP because controlling HCl will 
result in control of other inorganic HAP emissions (as no liquid oil-
fired EGU has an FGD system installed, there is no effective control in 
use and the surrogacy argument is invalid). As discussed elsewhere, EPA 
is also proposing to set an alternative equivalent SO2 
emission limit for coal-fired EGUs with some form of FGD system 
installed as: (1) The controls for SO2 are also effective 
controls for HCl and the other acid gas-HAP; and (2) most, if not all, 
EGUs already have SO2 CEMS in-place. Thus, SO2 
CEMS could serve as the compliance monitoring mechanism for such units. 
EGUs without an FGD system installed would not be able to use the 
alternate SO2 emission limit, and EGUs must operate their 
FGD at all times to use the alternate SO2 emission limit.
    EPA is proposing work practice standards for non-dioxin/furan 
organic and dioxin/furan organic HAP. The significant majority of 
measured emissions from EGUs of these HAP were below the detection 
levels of the EPA test methods, and, as such, EPA considers it 
impracticable to reliably measure emissions from these units. As the 
majority of measurements are so low, doubt is cast on the true levels 
of emissions that were measured during the tests. Overall, 1,552 out of 
2,334, total test runs for dioxin/furan organic HAP contained data 
below the detection level for one or more congeners, or 67 percent of 
the entire data set. In several cases, all of the data for a given run 
were below the detection level; in few cases were the data for a given 
run all above the detection level. For the non-dioxin/furan organic 
HAP, for the individual HAP or constituent, between 57 and 89 percent 
of the run data were comprised of values below the detection level. 
Overall, the available test methods are technically challenged, to the 
point of providing results that are questionable for all of the organic 
HAP. For example, for the 2010 ICR testing, EPA extended the sampling 
time to 8 hours in an attempt to obtain data above the MDL. However, 
even with this extended sampling time, such data were not obtained 
making it questionable that any amount of effort, and, thus, expense, 
would make the tests viable. Based on the difficulties with accurate 
measurements at the levels of organic HAP encountered from EGUs and the 
economics associated with units trying to apply measurement methodology 
to test for compliance with numerical limits, we are proposing a work 
practice standard under CAA section 112(h).
    We do not believe that this approach is inconsistent with that 
taken on other NESHAP where we also had issues with data at or below 
the MDL (e.g., Portland Cement NESHAP; Boiler NESHAP). In the case of 
the Portland Cement NESHAP, the MDL issue was with HCl (a single 
compound HAP as opposed to the oftentimes multi-congener organic HAP), 
and in data from only 3 of 21 facilities. As noted elsewhere in this 
preamble, we dealt with similar MDL issues with HCl in establishing the 
limits in this proposed rule. In the case of the Boiler NESHAP, the MDL 
issue was with the organic HAP. For that rulemaking, the required 
sampling time during conducting of the associated ICR was 4 hours, as 
opposed to the 8 hours required in the 2010 ICR. Further, a review of 
the data indicates that the dioxin/furan HAP levels (a component of the 
organic HAP) were at least 7 times greater, on average, for coal-fired 
IB units and 3 times greater, on average, for oil-fired IB units than 
from similar EGUs. We think this difference is significant from a 
testing feasibility perspective.
    For all the other HAP, as stated above, we are proposing to 
establish numerical emission rate limitations; however, we did consider 
using a percent reduction format for Hg (e.g., the percent efficiency 
of the control device, the percent reduction over some input amount, 
etc.). 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 EPA's desire to promote, and give 
credit for, coal preparation practices that remove Hg and other HAP 
before firing (i.e., coal washing or beneficiation, actions that may be 
taken at the mine site rather than at the site of the EGU). 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. In addition, 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, 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. EPA believes, however, 
that an emission rate format allows for, and promotes, the use of 
precombustion HAP removal processes because such practices will help 
sources assure they will comply with the proposed standard. 
Furthermore, a percent reduction requirement would 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 55,002; September 9, 2010), EPA believes that a percent 
reduction format negates the contribution of HAP inputs to EGU 
performance and, thus, may be inconsistent with the DC Circuit Court's 
rulings as restated in Brick MACT (479 F.3d at 880) that 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 the point relating to plant inputs likely 
playing a role in emissions in that they 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). For all of these 
reasons, we are proposing to establish numerical emission standards for 
HAP emissions from EGUs with the exception of the organic HAP standard 
which is in the form of work practices.

C. How did EPA determine the proposed emission limitations for existing 
EGUs?

    All standards established pursuant to CAA section 112(d)(2) must 
reflect MACT, the maximum degree of reduction in emissions of air 
pollutants that the Administrator, taking into consideration the cost 
of achieving such emissions reductions, and any nonair

[[Page 25041]]

quality health and environmental impacts and energy requirements, 
determines is achievable for each category. For existing sources, MACT 
cannot be less stringent than the average emission limitation achieved 
by the best performing 12 percent of existing sources (for which the 
Administrator has emissions information) for categories and 
subcategories with 30 or more sources or the best performing 5 sources 
for subcategories with less than 30 sources. This requirement 
determines the MACT floor for existing EGUs. However, EPA may not 
consider costs or other impacts in determining the MACT floor. EPA must 
consider cost, nonair quality health and environmental impacts, and 
energy requirements in connection with any standards that are more 
stringent than the MACT floor (beyond-the-floor controls).

D. How did EPA determine the MACT floors for existing EGUs?

    EPA must consider available emissions information to determine the 
MACT floors. For each pollutant, we calculated the MACT floor for a 
subcategory of sources by ranking all the available emissions data 
obtained through the 2010 ICR\158\ from units within the subcategory 
from lowest emissions to highest emissions (on a lb/MMBtu basis), and 
then taking the numerical average of the test results from the best 
performing (lowest emitting) 12 percent of sources.
---------------------------------------------------------------------------

    \158\ Earlier data were not used due to concerns related to 
changes in test and analytical methods.
---------------------------------------------------------------------------

    Therefore, the MACT floor limits for each of the HAP and HAP 
surrogates are calculated based on the performance of the lowest 
emitting (best performing) sources in each of the subcategories.
    As discussed above, for coal-fired EGUs, EPA established the MACT 
floors for non-Hg metallic HAP and non-metallic inorganic (acid gas) 
HAP based on sources representing 12 percent of the number of sources 
in the subcategory. For Hg from coal-fired units and all HAP from oil-
fired units, EPA established the MACT floors based on sources 
representing 12 percent of the sources for which the Agency had 
emissions information. The IGCC and solid oil-fired EGU subcategories 
each have less than 30 units so the MACT floors were determined using 
the 5 best performing sources (or 2 sources for IGCC because there are 
only 2 such sources in the subcategory). The MACT floor limitations for 
each of the HAP and HAP surrogates (PM, Hg, and HCl) are calculated 
based on the performance of the lowest emitting (best performing) 
sources in each of the subcategories. The initial sort of the 
respective data to determine the MACT floor pool for analysis was made 
on the ``lb/MMBtu'' formatted data; this same pool of EGUs was then 
used for the ``lb/MWh'' analysis and all analyses were based on the 
data provided through the 2010 ICR.
    We used the emissions data for those best performing affected 
sources to determine the emission limitations to be proposed, with an 
accounting for variability. EPA must exercise its judgment, based on an 
evaluation of the available data, to determine the level of emissions 
control that has been achieved by the best performing sources under 
variable conditions. The DC Circuit Court has recognized that EPA may 
consider variability in estimating the degree of emission reduction 
achieved by best-performing sources in setting MACT floors. See 
Mossville Envt'l Action Now v. EPA, 370 F.3d 1232, 1241-42 (DC Cir 
2004) (holding EPA may consider emission variability in estimating 
performance achieved by best-performing sources and may set the floor 
at a level that best-performing source can expect to meet ``every day 
and under all operating conditions'').
    In determining the MACT floor limitations, we first determine the 
floor, which is the level achieved in practice by the average of the 
top 12 percent of similar sources for subcategories with more than 30 
sources. We then assess variability of the best performers by using a 
statistical formula designed to estimate a MACT floor level that is 
achieved by the average of the best performing sources with some 
confidence (e.g., 99 percent confidence) if the best performing sources 
were able to replicate the compliance tests in our data base. 
Specifically, the MACT floor limit is an upper prediction limit (UPL) 
calculated with the Student's t-test using the TINV function in 
Microsoft Excel. The Student's t-test has also been used in other EPA 
rulemakings (e.g., NSPS for Hospital/Medical/Infectious Waste 
Incinerators; NESHAP for IB and Portland Cement) in accounting for 
variability. A prediction interval for a future observation, or an 
average of future observations, is an interval that will, with a 
specified degree of confidence, contain the next (or the average of 
some other pre-specified number of) randomly selected observation(s) 
from a population. In other words, the prediction interval estimates 
what the range of future values, or average of future values, will be, 
based upon present or past background samples taken. Given this 
definition, the UPL represents the value which we can expect the mean 
of three future observations (3-run average) to fall below, based upon 
the results of an independent sample from the same population. In other 
words, if we were to randomly select a future test condition from any 
of these sources (i.e., average of 3 runs), we can be 99 percent 
confident that the reported level will fall at or below the UPL value. 
To calculate the UPL, we used the average (or sample mean) and an 
estimate of the standard deviation, which are two statistical measures 
calculated from the available data. The average is a measure of 
centrality of the distribution. Symmetric distributions such as the 
normal are centered around the average. The standard deviation is a 
common measure of the dispersion of the data set around the average.
    We first determined the distribution of the emissions data for the 
best-performing 12 percent of units within each subcategory prior to 
calculating UPL values. When the sample size is 15 or larger, one can 
assume based on the Central Limit theorem, that the sampling 
distribution of the average or sampling mean of emission data is 
approximately normal, regardless of the parent distribution of the 
data. This assumption justifies selecting the normal-distribution based 
UPL equation for calculating the floor.
    When the sample size is smaller than 15 and the distribution of the 
data is unknown, the Central Limit Theorem can't be used to support the 
normality assumption. Statistical tests of the kurtosis, skewness, and 
goodness of fit are then used to evaluate the normality assumption. To 
determine the distribution of the best performing dataset, we first 
computed the skewness and kurtosis statistics and then conducted the 
appropriate small-sample hypothesis tests. The skewness statistic (S) 
characterizes the degree of asymmetry of a given data distribution. 
Normally distributed data have a skewness of zero (0). A skewness 
statistic that is greater (less) than 0 indicates that the data are 
asymmetrically distributed with a right (left) tail extending towards 
positive (negative) values. Further, the standard error of the skewness 
statistic (SES) can be approximated by SES = SQRT(6/N) where N is the 
sample size. According to the small sample skewness hypothesis test, if 
S is greater than two times the SES, the data distribution can be 
considered non-normal. The kurtosis statistic (K) characterizes the 
degree of peakedness or flatness of a given data distribution in 
comparison to a normal distribution. Normally distributed data have a 
kurtosis of 0. A kurtosis statistic that is greater (less) than 0 
indicates a

[[Page 25042]]

relatively peaked (flat) distribution. Further, the standard error of 
the kurtosis statistic (SEK) can be approximated by SEK = SQRT(24/N) 
where N is the sample size. According to the small sample kurtosis 
hypothesis test, if K is greater than two times the SEK, the data 
distribution is typically considered to be non-normal.
    The skewness and kurtosis hypothesis tests were applied to both the 
reported test values and the lognormal values (using the LN() function 
in Excel) of the reported test values. If S and K of the reported data 
set were both less than twice the SES and SEK, respectively, the 
dataset was classified as normally distributed. If neither S nor K, or 
only one of these statistics, were less than twice the SES or SEK, 
respectively, then we looked at the skewness and kurtosis hypothesis 
test results conducted for the natural log-transformed data. Then, the 
distribution most similar to a normal distribution was selected as the 
basis for calculating the UPL. If the results of the skewness and 
kurtosis hypothesis tests were mixed for the reported values and the 
natural log-transformed reported values, we chose the normal 
distribution to be conservative. We believe this approach is more 
accurate and obtained more representative results than a more 
simplistic normal distribution assumption.
    Because some of the MACT floor emission limitations are based on 
the average of a 3-run test, and compliance with these limitations will 
be based on the same, the UPL for data considered to be normally 
distributed is calculated by:
[GRAPHIC] [TIFF OMITTED] TP03MY11.000


Where:
n = the number of test runs
m = the number of test runs in the compliance average
[ballot] = mean of the data from top performing sources calculated 
as
[GRAPHIC] [TIFF OMITTED] TP03MY11.001

t(0.99, n-1) is the 99th percentile of the T-Student distribution 
with n-1 degrees of freedom
s2 = variance of the data from top performing sources 
calculated as
[GRAPHIC] [TIFF OMITTED] TP03MY11.002


    This calculation was performed using the following Excel function:
    Normal distribution: 99% UPL = AVERAGE(Test Runs in Top 12%) + 
[STDEV(Test Runs in Top 12%) x TINV(2 x probability, n-1 degrees of 
freedom)*SQRT((1/n)+(1/3))], for a one-tailed t-value (with 2 x 
probability), probability of 0.01, and sample size of n.
    Data from only a single unit was used in establishing the new-
source floor. Analysis based solely in these single-data-point-per-unit 
observations does not capture any within source variability. When 
additional information (e.g., stack averages) from the past 5 years 
(from the 2010 ICR) was available, we combined the current and past 
data and calculated an estimate of the variance term, s\2\, that 
intends to include the within and between source variability. The most 
recent data (e.g., single floor average) were used to calculate the 
average in the UPL equation. The UPL equation for this case was 
calculated as:
[GRAPHIC] [TIFF OMITTED] TP03MY11.003

UPL =
Where:
m = the number of test runs in the compliance average
N = the number of units involved in calculating the average (a 
single measurement (e.g., floor average) per unit)
ni = number of data points (e.g., stack averages) collected in the 
past for the i\th\ source
[GRAPHIC] [TIFF OMITTED] TP03MY11.004

number of data points (floor average plus stack averages) available 
to calculate the variance
df = n-1
xi = current information (e.g., single floor average) for the i\th\ 
source
yi = past information (e.g., stack average) for the i\th\ source
m = the number of future test runs in the compliance average
[ballot] = mean of the data from top performing sources calculated 
as
[GRAPHIC] [TIFF OMITTED] TP03MY11.005


[[Page 25043]]


[GRAPHIC] [TIFF OMITTED] TP03MY11.006

s\2\ = variance calculated as
[GRAPHIC] [TIFF OMITTED] TP03MY11.007

\t\df,.99 = quantile t-distribution with df degrees of 
freedom at 99 percent confidence level df = degrees of freedom = n - 1
    The calculation of this UPL was performed using the following Excel 
function:
    Normal distribution: 99% UPL = AVERAGE(Test Runs in Top 12%) + 
[STDEV(Test Runs in Top 12%, stack averages) x TINV(2 x probability, 
(n-1) degrees of freedom)*SQRT((1/N)+(\1/3\))], for a one-tailed t-
value (with 2 x probability), probability of 0.01, and sample size of 
n.
    The UPL, to test compliance based on a 3-run average and assuming 
log-normal data, is calculated by (Bhaumik and Gibbons, 2004):
[GRAPHIC] [TIFF OMITTED] TP03MY11.008

[GRAPHIC] [TIFF OMITTED] TP03MY11.009

[sgr] = the variance estimate of the log transformed data from the top 
performing sources calculated as:
[GRAPHIC] [TIFF OMITTED] TP03MY11.010

z99 = the 99\th\-percentile of the log-normal 
distribution estimated using the trapezoidal rule approach from the 
following equation
[GRAPHIC] [TIFF OMITTED] TP03MY11.011


[[Page 25044]]


    The calculation of the log-normal based UPL was performed using the 
following Excel function:
    Normal distribution: 99% UPL = EXP(AVERAGE(LN(Test Runs in Top 
12%)) + VAR(LN(Test Runs in Top 12%))/2) + (99\TH\-PERCENTILE LOGNORMAL 
DISTRIBUTION/m)*
    SQRT(m*EXP(2* AVERAGE(LN(Test Runs in Top 12%))+ VAR(LN(Test Runs 
in Top 12%)))*(EXP(VAR(LN(Test Runs in Top 12%)))-1)+m[caret]2* EXP(2* 
AVERAGE(LN(Test Runs in Top 12%))+ VAR(LN(Test Runs in Top 
12%)))*(VAR(LN(Test Runs in Top 12%))/n+ VAR(LN(Test Runs in Top 
12%))[caret]2/(2*(n-1)))).
    The 99\th\ percentile of the log-normal distribution, 
z.99, was calculated following Bhaumik and Gibbons (2004).
    Test method measurement imprecision can also be a component of data 
variability. At very low emissions levels, as encountered in some of 
the data used to support this proposed rule, the inherent imprecision 
in the pollutant measurement method has a large influence on the 
reliability of the data underlying the regulatory floor or beyond-the-
floor emissions limit. Of particular concern are those data that are 
reported near or below a test method's pollutant detection capability. 
In our guidance for reporting pollutant emissions used to support this 
proposed rule, we specified the criteria for determining test-specific 
MDL. Those criteria ensure that there is about a 1 percent probability 
of an error in deciding that the pollutant measured at the MDL is 
present when in fact it was absent. Such a probability is also called a 
false positive or the alpha, Type I, error. Another view of this 
probability is that one is 99 percent certain of the presence of the 
pollutant measured at the MDL. Because of matrix effects, laboratory 
techniques, sample size, and other factors, MDLs normally vary from 
test to test. We requested sources to identify (i.e., flag) data which 
were measured below the MDL and to report those values as equal to the 
test-specific MDL.
    Variability of data due to measurement imprecision is inherently 
and reasonably addressed in calculating the floor emissions limit when 
the data distribution, which would include the results of all tests, is 
significantly above the MDL. Should the data distribution shift such 
that some or many test results are below the MDL but are reported as 
MDL values, as is the case for some of our database, then other 
techniques need to be used to account for data variability. Indeed, 
under such a shift, the distribution becomes truncated on the lower 
end, leading to an artificial overabundance of values occurring at the 
MDL. Such an artificial overabundance of values could, if not adjusted, 
lead to erroneous floor calculations; those unadjusted floor 
calculations may be higher than otherwise expected, because no values 
reported below the MDL are included in the calculation. There is a 
concern that a floor emissions limit based on a truncated data base may 
not account adequately for data measurement variability and that a 
floor emissions limit calculated using values at or near the MDL may 
not account adequately for data measurement variability, because the 
measurement error associated with those values provides a large degree 
of uncertainty--up to 100 percent.
    Despite our concern that accounting for measurement imprecision 
should be an important consideration in calculating the floor emissions 
limit, we did not adjust the calculated floor for the data used for 
this proposed rule because we do not know how to develop such an 
adjustment. We remain open to considering approaches for making such an 
adjustment, particularly when those approaches acknowledge our 
inability to detect with certainty those values below the MDL. We 
request comment on approaches suitable to account for measurement 
variability in establishing the floor emissions limit when based on 
measurements at or near the MDL.
    As noted above, the confidence level that a value measured at the 
detection level is greater than 0 is about 99 percent. The expected 
measurement imprecision for an emissions value occurring at or near the 
MDL is about 40 to 50 percent. Pollutant measurement imprecision 
decreases to a consistent relative 10 to 15 percent for values measured 
at a level about three times the MDL.\159\ One approach that we believe 
could be applied to account for measurement variability would require 
defining a MDL that is representative of the data used in establishing 
the floor emissions limitations and also minimizes the influence of an 
outlier test-specific MDL value. The first step in this approach would 
be to identify the highest test-specific MDL reported in a data set 
that is also equal to or less than the floor emissions limit calculated 
for the data set. This approach has the advantage of relying on the 
data collected to develop the floor emissions limit while to some 
degree minimizing the effect of a test(s) with an inordinately high MDL 
(e.g., the sample volume was too small, the laboratory technique was 
insufficiently sensitive, or the procedure for determining the 
detection level was other than that specified).
---------------------------------------------------------------------------

    \159\ American Society of Mechanical Engineers, Reference Method 
Accuracy and Precision (ReMAP): Phase 1, Precision of Manual Stack 
Emission Measurements, CRTD Vol. 60, February 2001.
---------------------------------------------------------------------------

    The second step would be to determine the value equal to three 
times the representative MDL and compare it to the calculated floor 
emissions limit. If three times the representative MDL were less than 
the calculated floor emissions limit, we would conclude that 
measurement variability is adequately addressed and we would not adjust 
the calculated floor emissions limit. If, on the other hand, the value 
equal to three times the representative MDL were greater than the 
calculated floor emissions limit, we would conclude that the calculated 
floor emissions limit does not account entirely for measurement 
variability. We then would use the value equal to three times the MDL 
in place of the calculated floor emissions limit to ensure that the 
floor emissions limit accounts for measurement variability. This 
adjusted value would ensure measurement variability is adequately 
addressed in the floor or the emissions limit. This check was part of 
the variability analysis for all new MACT floors that had below 
detection level (BDL) or detection level limited (DLL) run data present 
in the best controlled data set and resulted in the MACT floors being 
three times the MDL rather than the UPL in a limited number of 
instances (see ``MACT Floor Analysis (2011) for the Subpart UUUUU--
National Emission Standards for Hazardous Air Pollutants: Coal- and 
Oil-fired Electric Utility Steam Generating Units'' (MACT Floor Memo) 
in the docket). We request comment on this approach.
    As previously discussed, we account for variability in setting 
floors, not only because variability is an element of performance, but 
because it is reasonable to assess best performance over time. For 
example, we know that the HAP emission data from the best performing 
units are, for the most part, short-term averages, and that the actual 
HAP emissions from those sources will vary over time. If we do not 
account for this variability, we would expect that even the units that 
perform better than the floor on average could potentially exceed the 
floor emission levels a part of the time which would mean that 
variability was not properly taken into account. This variability may 
include the day-to-day variability in the total fuel-borne HAP input to 
each unit; variability of the sampling and analysis methods; and 
variability resulting from site-to-site differences for the best

[[Page 25045]]

performing units. EPA's consideration of variability accounted for that 
variability exhibited by the data representing multiple units and 
multiple data values for a given unit (where available). We calculated 
the MACT floor based on the UPL (upper 99th percentile) as described 
earlier from the average performance of the best performing units, 
Student's t-factor, and the variability of the best performing units.
    We believe 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. Both the 
analysis of the measured emissions from units representative of the top 
12 percent, and the variability analysis, are reasonably designed to 
provide a meaningful estimate of the average performance, or central 
tendency, of the best controlled 12 percent of units in a given 
subcategory.
    A detailed discussion of the MACT floor methodology is presented in 
the MACT Floor Memo in the docket.
1. Determination of MACT for the Fuel-borne HAP for Existing Sources
    In developing the proposed MACT floor for the fuel-borne HAP (non-
Hg metals, acid gases, and Hg), as described earlier, we are using PM 
as a surrogate for non-Hg metallic HAP (except for the liquid oil-fired 
subcategory) and HCl as a surrogate for the acid gases (except for the 
liquid oil-fired subcategory). Table 12 of this preamble presents the 
number of units in each of the subcategories, along with the number of 
units comprising the best performing units (top 12 percent). Table 12 
of this preamble also shows the average emission level of the top 12 
percent, and the MACT floor including consideration of variability (99 
percent UPL of top 12 percent).

                          Table 12--Summary of MACT Floor Results for Existing Sources
----------------------------------------------------------------------------------------------------------------
          Subcategory                   Parameter                PM                HCl              Mercury
----------------------------------------------------------------------------------------------------------------
Coal-fired unit designed for     No. of sources in       1,091............  1,091............  1,061.
 coal >= 8,300 Btu/lb.            subcategory.
                                 No. in MACT floor.....  131..............  131..............  40.
                                 Avg. of top 12%.......  0.02 lb/MMBtu....  0.0003 lb/MMBtu..  0.01 lb/TBtu.
                                 99% UPL of top 12%....  0.030 lb/MMBtu...  0.0020 lb/MMBtu..  1.0 lb/TBtu.
Coal-fired unit designed for     No. of sources in       1,091............  1,091............  30.
 coal < 8,300 Btu/lb.             subcategory.
                                 No. in MACT floor.....  131..............  131..............  2.
                                                                                               1.*
                                 Avg. of top 12%.......  0.02 lb/MMBtu....  0.0003 lb/MMBtu..  1 lb/TBtu.
                                                                                               (1 lb/TBtu *).
                                 99% UPL of top 12%....  0.030 lb/MMBtu...  0.0020 lb/MMBtu..  11.0 lb/TBtu.
                                                                                               (4.0 lb/TBtu *).
IGCC...........................  No. of sources in       2................  2................  2.
                                  subcategory.
                                 No. in MACT floor.....  2................  2................  2.
                                 Avg...................  0.03 lb/MMBtu....  0.0002 lb/MMBtu..  0.9 lb/TBtu.
                                 99% UPL...............  0.050 lb/MMBtu...  0.00050 lb/MMBtu.  3.0 lb/TBtu.
Solid oil-derived..............  No. of sources in       10...............  10...............  10.
                                  subcategory.
                                 No. in MACT floor.....  5................  5................  5.
                                 Avg. of top 5.........  0.04 lb/MMBtu....  0.002 lb/MMBtu...  0.09 lb/TBtu.
                                 99% UPL of top 5......  0.20 lb/MMBtu....  0.0050 lb/MMBtu..  0.20 lb/TBtu.
                                                         Total metals **..  HCl..............  Mercury.
Liquid oil.....................  No. of sources in       154..............  154..............  154.
                                  subcategory.
                                 No. in MACT floor.....  7................  7................  7.
                                 Avg. of top 12%.......  0.00002 lb/MMBtu.  0.0001 lb/MMBtu..  NA.
                                 99% UPL of top 12%....  0.000030 lb/MMBtu  0.00030 lb/MMBtu.  NA.
----------------------------------------------------------------------------------------------------------------
* Beyond-the-floor limit as discussed elsewhere.
** Includes Hg.
NA = Not applicable.

    For the ``Coal-fired unit designed for coal < 8,300 Btu/lb'' 
subcategory, we used 12 percent of the available data (11 data points), 
or 2 units, in setting the existing source floor for Hg. For the IGCC 
subcategory, we used data from both units in setting the existing 
source floor. For the oil-fired subcategory, we did not include data 
obtained from EGUs co-firing natural gas in the existing-source MACT 
floor analysis because those emissions are not representative of EGUs 
firing 100 percent fuel oil.
    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. 
Further, we are proposing a total metals limit for oil-fired EGUs that 
includes Hg, in lieu of a PM limit, based on compliance through fuel 
analysis. We solicit comment on whether a PM limit or a total metals 
limit based on stack testing is an appropriate alternative. We 
recognize that PM is not an appropriate surrogate for Hg because Hg is 
not controlled to the same extent by the technologies which control 
emissions of other HAP metals, but we are soliciting comment as to 
whether there is anything unique as to oil-fired EGUs that would allow 
us to conclude that PM is an appropriate surrogate for all HAP metal 
emissions from such units. We further solicit comment on whether we 
should be setting a separate standard for Hg if we require end-of-stack 
testing for a total metals limit. Based on the data we have, that Hg 
limit would be 0.050 lb/MMBtu (0.000070 lb/GWh) for existing oil-fired 
units and 0.00010 lb/GWh for new oil-fired units. In this regard, we 
request additional Hg emissions data from oil-fired EGUs. Although we 
have some data, additional

[[Page 25046]]

data would aid in our development of the standards for such units.
2. Determination of the Work Practice Standard
    CAA section 112(h)(1) states that the Administrator may prescribe a 
work practice standard or other requirements, consistent with the 
provisions of CAA sections 112(d) or (f), in those cases where, in the 
judgment of the Administrator, it is not feasible to enforce an 
emission standard. CAA section 112(h)(2)(B) further defines the term 
``not feasible'' in this context to apply when ``the application of 
measurement technology to a particular class of sources is not 
practicable due to technological and economic limitations.''
    As noted earlier, the significant majority of the measured 
emissions from EGUs of dioxin/furan and non-dioxin/furan organic HAP 
are at or below the MDL of the EPA test methods even though we required 
8 hour test runs. As such, EPA considers it impracticable to reliably 
measure emissions from these units. As mentioned earlier, because the 
expected measurement imprecision for an emissions value occurring at or 
near the MDL is about 40 to 50 percent, we are uncertain of the true 
levels of organic HAP emissions that would be obtained during any test 
program. Overall, the fact that the organic HAP emission levels found 
at EGUs are so near the MDL achievable by the available test methods 
indicates that the results obtained are questionable for all of the 
organic HAP.
    Because the levels of organic HAP emissions from EGUs are so low 
(at or below the MDL of the available test methods), there is no 
indication that expending additional cost (i.e., extending the sampling 
time) would provide the regulated community the ability to test for 
these HAP that would provide reliable, technically viable results. In 
fact, the 2010 ICR testing required a longer testing period than 
normally used and the results were still predominantly below the MDL. 
Because of the technical infeasibility, the economic infeasibility is 
that sources do not have a way to demonstrate compliance that is 
legitimate and we conclude no additional cost will improve the results.
    Based on this analysis, and considering the fact that regardless of 
the cost, the resulting emissions data would be suspect due to the 
detection level issues, the Administrator is proposing under CAA 
section 112(h) that it is not feasible to enforce emission standards 
for dioxin/furan and non-dioxin/furan organic HAP because of the 
technological and economic infeasibility described above. Thus, a work 
practice, as discussed below, is being proposed to limit the emission 
of these HAP for existing EGUs.
    For existing units, the only work practice we identified that would 
potentially control these HAP emissions is an annual performance test. 
Organic HAP are formed from incomplete combustion of the fuel. The 
objective of good combustion is to release all the energy in the fuel 
while minimizing losses from combustion imperfections and excess air. 
The combination of the fuel with the O2 requires temperature 
(high enough to ignite the fuel constituents), mixing or turbulence (to 
provide intimate O2-fuel contact), and sufficient time (to 
complete the process), sometimes referred to the three Ts of 
combustion. Good combustion practice (GCP), in terms of combustion 
units, could be defined as the system design and work practices 
expected to minimize the formation and maximize the destruction of 
organic HAP emissions. We maintain that the proposed work practice 
standards will promote good combustion and thereby minimize the organic 
HAP emissions we are proposing to regulate in this manner.

E. How did EPA consider beyond-the-floor options for existing EGUs?

    Once the MACT floors were established for each subcategory, we 
considered various regulatory options more stringent than the MACT 
floor level of control (i.e., technologies or other work practices that 
could result in lower emissions) for the different subcategories.
    Except for one subcategory, we could not identify better HAP 
emissions reduction approaches that could achieve greater emissions 
reductions of HAP than the control technology combination(s) (e.g., FF, 
carbon injection, scrubber, and GCP) that we expect will be used to 
meet the MACT floor levels of control (and that are already in use on 
EGUs comprising the top performing 12 percent of sources), though we 
did consider duplicate controls (e.g., multiple scrubbers) in series 
and found the cost of that option unreasonable.
    Fuel switching to natural gas is an option that would reduce HAP 
emissions. We determined that fuel switching was not an appropriate 
beyond-the-floor option. First, natural gas supplies are not available 
in some areas. Natural gas pipelines are not available in all regions 
of the U.S., and natural gas may not be available as a fuel for many 
EGUs. Moreover, even where pipelines provide access to natural gas, 
supplies of natural gas may not be adequate, especially during peak 
demand (e.g., the heating season). Under such circumstances, there 
would be some units that could not comply with a requirement to switch 
to natural gas. While the combined capital cost and O&M costs for a 
coal-to-gas retrofit could be less than that of a combined retrofit 
with ACI and either DSI or FGD, the increased fuel costs of coal-to-gas 
cause its total incremental COE at a typical EGU is likely to be 
significantly larger than the incremental COE of the other retrofit 
options available. For example, an EPA analysis detailed in an 
accompanying TSD found that the incremental COE of coal-to-gas was 4 to 
22 times the cost of alternatives, although the magnitude of the 
difference would change with alternative fuel price assumptions. EPA, 
therefore, concludes that the coal-to-gas option is not a cost-
effective means of achieving HAP reductions for the purposes of this 
proposed rule.
    Additional detail on the economics of coal-to-gas conversion and 
illustrative calculations of additional emission reductions versus cost 
impacts are provided in the ``Coal-to-Gas Conversion'' TSD in the 
docket.
    As noted earlier, no EGU 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 a EGU with a height-to-depth 
ratio of 3.82 or greater was found among the top performing 12 percent 
of sources for Hg emissions, even though some of these units employed 
ACI. EPA has learned that the units of this design that were using ACI 
during the testing were using ACI to meet their permitted Hg emission 
levels. However, EPA believes that the control level being achieved is 
still not that which could be achieved if ACI were used to its fullest 
extent. Therefore, EPA is proposing to establish a beyond-the-floor 
emission limit for existing 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 a EGU with a height-to-depth 
ratio of 3.82 or greater. The proposed emission limit is 4 lb/TBtu for 
existing EGUs in this class. This proposed emission limit is based on 
use of the data from the top performing unit in the subcategory made 
available to the Agency through the 2010 ICR; the same statistical 
analyses were conducted as were done to establish the MACT floor values 
for the other HAP. EPA notes that our analysis shows that the 
technology installed to achieve the MACT floor

[[Page 25047]]

limit would be the same technology used to achieve the beyond-the-floor 
MACT limit and, thus, proposing to go beyond-the-floor is reasonable. 
EPA solicits comment on whether it is appropriate to propose a beyond-
the-floor limit for existing EGUs in this subcategory.
    To assess the impacts on the existing EGUs in this subcategory to 
implement the proposed beyond-the-floor limit, EPA conducted analyses 
using approaches as discussed in the memoranda ``Beyond-the-Floor 
Analysis (2011) for the Subpart UUUUU--National Emission Standards for 
Hazardous Air Pollutants: Coal- and Oil-fired Electric Utility Steam 
Generating Units'' and ``Emission Reduction Costs for the Beyond-the-
Floor Mercury Rate in the Toxics Rule'' in the docket. The cost 
effectiveness of the beyond-the-floor option ranged from $17,375 to 
$21,393/lb Hg removed in the two approaches. The total costs of the 
non-air environmental impacts for the proposed beyond-the-floor limit 
for this subcategory are estimated as $12,310. Non-air quality health 
impacts were evaluated, but no incremental health impacts were 
attributable to installation of FF and ACI, because these technologies 
do not expose electric utility employees or the public to any 
additional health risks above the risks attributable to current utility 
operations involving compressed air systems, confined spaces, and 
exposure to fly ash.
    EPA is aware that there may be other means of enhancing the removal 
of Hg from the flue gas stream (e.g., spraying a halogen such as 
chlorine or bromine on the coal as it is fed to the EGU). EPA has 
information that indicates that such means were employed by an unknown 
number of EGUs during the period of time they were testing to provide 
data in compliance with the 2010 ICR (see McMeekin memo in the docket). 
Thus, we believe that the performance of such means is reflected in the 
MACT floor analysis. However, EPA has no data upon which to assess 
whether any other technology would provide additional control to that 
already shown by the use of ACI and, thus, we are not proposing to use 
such technologies as the basis for a beyond-the-floor analysis. EPA 
solicits comment on this approach.
    EPA believes the best potential way of reducing Hg emissions from 
existing IGCC units is to remove Hg from the syngas before combustion. 
For example, an existing industrial coal gasification unit has 
demonstrated a process, using a sulfur-impregnated AC bed, which has 
proven to yield over 90 percent Hg removal from the coal syngas. 
(Rutkowski 2002.) We considered using carbon bed technology as beyond-
the-floor for existing IGCC units. However, we have no detailed data to 
support this position at this time and, thus, are not proposing a 
beyond-the-floor limit for existing IGCC units. EPA requests comments 
on whether the use of this or other control techniques have been 
demonstrated to consistently achieve emission levels that are lower 
than levels from similar sources achieving the proposed existing MACT 
floor level of control. Comments should include information on 
emissions, control efficiencies, reliability, current demonstrated 
applications, and costs, including retrofit costs.
    We considered proposing beyond-the-floor requirements for Hg in the 
other subcategories and for the other HAP in all of the subcategories. 
Activated carbon injection is used on EGUs designed for coal greater 
than or equal to 8,300 Btu/lb and, therefore, its effect on Hg removal 
has already been accounted for in the MACT floor. Further, EPA has no 
information that would indicate that ACI would provide significantly 
lower emission levels given the MACT floor Hg standard, and it is also 
possible that existing sources in this subcategory will utilize ACI to 
comply with the MACT floor limit. Activated carbon injection has not 
been demonstrated on liquid oil-fired EGUs. Similarly, ACI has not been 
demonstrated on solid oil-derived fuel-fired EGUs. EPA has no 
information that would indicate that ACI would provide significantly 
lower Hg emission levels on units operating at the level of the MACT 
floor. For the non-Hg metallic and acid gas HAP, there is no technology 
that would achieve additional control over that being shown by units 
making up the floor. Additional combinations of controls (e.g., dual 
FGD systems in series) could be used but at a significant additional 
cost and, given the MACT floor level of control, a minimal additional 
reduction in HAP emissions. For the organic HAP, EPA is not aware of 
any measures beyond those proposed here that would result in lower 
emissions. Therefore, EPA is not proposing beyond-the-floor limitations 
other than as noted above.

F. Should EPA consider different subcategories?

    EPA has attempted to identify subcategories that provide the most 
reasonable basis for grouping and estimating the performance of 
generally similar units using the available data. We believe that the 
subcategories we selected are appropriate.
    EPA requests comments on whether additional or different 
subcategories should be considered. Comments should include detailed 
information regarding why a new or different subcategory is appropriate 
(based on the available data and on the statutory constraint of 
``class, type or size''), how EPA should define any additional and/or 
different subcategories, how EPA should account for varied or changing 
fuel mixtures, and how EPA should use the available data to determine 
the MACT floor for any new or different subcategories.

G. How did EPA determine the proposed emission limitations for new 
EGUs?

    All standards established pursuant to CAA section 112 must reflect 
MACT, the maximum degree of reduction in emissions of air pollutants 
that the Administrator, taking into consideration the cost of achieving 
such emissions reductions, and any nonair quality health and 
environmental impacts and energy requirements, determines is achievable 
for each category. The CAA specifies that MACT for new EGUs shall not 
be less stringent than the emission control that is achieved in 
practice by the best-controlled similar source. This minimum level of 
stringency is the MACT floor for new units. However, EPA may not 
consider costs or other impacts in determining the MACT floor. EPA must 
consider cost, nonair quality health and environmental impacts, and 
energy requirements in connection with any standards that are more 
stringent than the MACT floor (beyond-the-floor controls).

H. How did EPA determine the MACT floor for new EGUs?

    Similar to the MACT floor process used for existing EGUs, the 
approach for determining the MACT floor must be based on available 
emissions test data. Using such an approach, we calculated the MACT 
floor for a subcategory of sources by ranking the 2010 ICR emissions 
data from EGUs within the subcategory from lowest to highest (on a lb/
MMBtu basis) to identify the best controlled similar source. The MACT 
floor limitations for each of the HAP and HAP surrogates (PM, Hg, and 
HCl) are calculated based on the performance (numerical average) of the 
lowest emitting (best controlled) source for each pollutant in each of 
the subcategories.
    The MACT floor limitations for new sources were calculated using 
the same formula as was used for existing sources with one exception. 
For the new source calculations, the results of the three individual 
emission test runs were used

[[Page 25048]]

instead of the 3-run average that was used in determining the existing-
source MACT floor. This was done to be able to provide some measure of 
variability. As previously discussed, we account for variability of the 
best-controlled source in setting floors, not only because variability 
is an element of performance, but because it is reasonable to assess 
best performance over time. We calculated the MACT floor based on the 
UPL (upper 99th percentile) as described earlier from the average 
performance of the best controlled similar source, Student's t-factor, 
and the total variability of the best-controlled source.
    This approach reasonably ensures that the emission limit selected 
as the MACT floor adequately represents the average level of control 
actually achieved by the best controlled similar source, considering 
ordinary operational variability.
    A detailed discussion of the MACT floor methodology is presented in 
the MACT Floor Memo in the docket.
    The approach that we use to calculate the MACT floors for new 
sources is somewhat different from the approach that we use to 
calculate the MACT floors for existing sources. Although the MACT 
floors for existing units are intended to reflect the performance 
achieved by the average of the best performing 12 percent of sources, 
the MACT floors for new units are meant to reflect the emission control 
that is achieved in practice by the best controlled similar source. 
Thus, for existing units, we are concerned about estimating the central 
tendency of a set of multiple units, whereas for new units, we are 
concerned about estimating the level of control that is representative 
of that achieved by a single best controlled source. As with the 
analysis for existing sources, the new EGU analysis must account for 
variability.
1. Determination of MACT for the Fuel-Borne HAP for New Sources
    In developing the MACT floor for the fuel-borne HAP (PM, HCl, and 
Hg), as described earlier, we are using PM as a surrogate for non-Hg 
metallic HAP and HCl as a surrogate for the acid gases (except for the 
liquid oil-fired subcategory). Table 13 of this preamble presents for 
each subcategory and fuel-borne HAP the average emission level of the 
best controlled similar source and the MACT floor which accounts for 
variability (99 percent UPL).

                                                 TAble 13--Summary of MACT Floor Results for New Sources
--------------------------------------------------------------------------------------------------------------------------------------------------------
             Subcategory                     Parameter                       PM                            HCl                         Mercury
--------------------------------------------------------------------------------------------------------------------------------------------------------
Coal-fired unit designed for coal     Avg. of top performer..  0.03 lb/MWh..................  0.2 lb/GWh..................  0.00001 lb/GWh.
 [gteqt] 8,300 Btu/lb.
                                      99% UPL of top           0.050 lb/MWh.................  0.30 lb/GWh.................  0.000010 lb/GWh.
                                       performer (test runs).
Coal-fired unit designed for coal <   Avg. of top performer..  0.03 lb/MWh..................  0.2 lb/GWh..................  0.02 lb/GWh.
 8,300 Btu/lb.
                                      99% UPL of top           0.050 lb/MWh.................  0.30 lb/GWh.................  0.040 lb/GWh.
                                       performer (test runs).
IGCC................................  Avg. of top performer..  N/A..........................  N/A.........................  N/A.
                                      99% UPL of top           0.050 lb/MWh *...............  0.30 lb/GWh *...............  0.000010 lb/GWh.*
                                       performer (test runs).
Solid oil-derived...................  Avg. of top performer..  0.04 lb/MWh..................  0.0003 lb/MWh...............  0.0007 lb/GWh.
                                      99% UPL of top           0.050 lb/MWh.................  0.00030 lb/MWh..............  0.0020 lb/GWh.
                                       performer (test runs).
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                      Total metals **                      HCl                         Mercury
                                     -------------------------------------------------------------------------------------------------------------------
Liquid oil..........................  Avg. of top performer..  0.00009 lb/MMBtu.............  0.0002 lb/MWh...............  NA.
                                      99% UPL of top           0.00040 lb/MMBtu.............  0.00050 lb/MWh..............  NA.
                                       performer (test runs).
--------------------------------------------------------------------------------------------------------------------------------------------------------
* Beyond-the-floor as discussed elsewhere.
** Includes Hg.
NA = Not applicable.

2. Determination of the Work Practice Standard
    We are proposing a work practice standards for non-dioxin/furan 
organic and dioxin/furan organic HAP under CAA section 112(h) that 
would require the implementation of an annual performance test program 
for new EGUs. This proposal for new EGUs is based on the same reasons 
discussed previously for existing EGUs. That is, the measured emissions 
from EGUs of these HAP are routinely below the detection limits of the 
EPA test methods, and, as such, EPA considers it impracticable to 
reliably measure emissions from these units.
    Thus, the work practice discussed above for existing EGUs is being 
proposed to limit the emissions of non-dioxin/furan organic and dioxin/
furan organic HAP for new EGUs.
    We request comments on this approach.

I. How did EPA consider beyond-the-floor for new units?

    The MACT floor level of control for new EGUs is based on the 
emission control that is achieved in practice by the best controlled 
similar source within each of the subcategories. No technologies were 
identified that would achieve HAP reduction greater than the new source 
floors for the subcategories, except for multiple controls in series 
(e.g., multiple FFs) which we consider to be unreasonable from a cost 
perspective.
    Fuel switching to natural gas is a potential regulatory option 
beyond the new source floor level of control that would reduce HAP 
emissions. However, natural gas supplies are not available in some 
areas. Thus, this potential control option may be unavailable to many 
sources in practice. Limited emissions reductions in combination with 
the high cost of fuel switching and considerations about the 
availability and technical feasibility of fuel switching makes this an 
unreasonable regulatory option that was not considered further. As 
discussed above, the uncertainties associated with nonair quality 
health and environmental impacts also argue against determining that 
fuel switching is reasonable beyond-the-floor option. In addition,

[[Page 25049]]

even if we determined that natural gas supplies were available in all 
regions, we would still not adopt this fuel switching option because it 
would effectively prohibit new construction of coal-fired EGUs and we 
do not think that is a reasonable approach to regulating HAP emissions 
from EGUs.
    Although, as discussed earlier for existing EGUs, EPA is proposing 
to establish a beyond-the-floor emission limit for Hg for existing EGUs 
designed to burn a nonagglomerating fuel having a calorific value 
(moist, mineral matter-free basis) of 19,305 kJ/kg (8,300 Btu/lb) or 
less in a EGU with a height-to-depth ratio of 3.82 or greater, EPA is 
not proposing to go beyond-the-floor for new EGUs in this subcategory. 
The proposed emission limit of 0.04 lb/GWh for new EGUs in this 
subcategory is based on use of ACI on a new unit and, we believe, 
reflects a level of performance achievable and, as noted above, no 
technologies were identified that would achieve HAP reduction greater 
than the new source floors for the subcategories, except for multiple 
controls in series (e.g., multiple FFs) which we consider to be 
unreasonable from a cost perspective.
    As discussed earlier, because of a lack of data, EPA is not 
proposing beyond-the-floor emission limits for existing IGCC units. 
However, EPA believes that the new-source limits derived from the data 
obtained from the two operating IGCC units are not representative of 
what a new IGCC unit could achieve. Therefore, EPA looked to the permit 
issued for the Duke Energy Edwardsport IGCC facility currently under 
construction.\160\ The permitted limits for this unit are similar to 
the limits derived from the existing units. Because of advances in 
technology, EPA does not believe that even these permitted levels are 
representative of what a modern IGCC unit could achieve. The emissions 
from IGCC units are normally predicted to be similar to or lower than 
those from traditional pulverized coal (PC) boilers. For example, DOE 
projects that future IGCC units will be able to meet a PM (filterable) 
emissions limit of 0.0071 lb/MMBtu, a SO2 emissions limit of 
0.0127 lb/MMBtu, and a Hg emissions limit of 0.571 lb/TBtu.\161\ 
Therefore, we are proposing that the new-source limits for new IGCC 
units be identical to those of new coal-fired units designed for coal 
greater than or equal to 8,300 Btu/lb. However, EPA has no information 
upon which to base the costs and non-air quality health, environmental, 
and energy impacts of this proposed approach. EPA solicits comment on 
this approach. Commenters should provide data that support their 
comment, including costs, emissions data, or engineering analyses.
---------------------------------------------------------------------------

    \160\ Letter from Matthew Stuckey, State of Indiana, to Mack 
Sims, Duke Energy Indiana. Operating permit fo Edwardsport 
Generating Station IGCC. Undated.
    \161\ DOE. Overview--Bituminous & Natural Gas to Electricity; 
Overview of Bituminous Baseline Study. From: Cost and Performance 
Baseline for Fossil Energy Plants, Vol. 1, DOE/NETL-2007/1281, May 
2007.
---------------------------------------------------------------------------

    Similarly, for the reasons discussed earlier for existing EGUs, EPA 
is not proposing any other beyond-the-floor emission limitations. EPA 
requests comments on whether the use of any control techniques have 
been demonstrated to consistently achieve emission levels that are 
lower than levels from similar sources achieving the proposed new-
source MACT floor levels of control. Comments should include 
information on emissions, control efficiencies, reliability, current 
demonstrated applications, and costs, including retrofit costs.

J. Consideration of Whether To Set Standards for HCl and Other Acid Gas 
HAP Under CAA Section 112(d)(4)

    We are proposing to set a conventional MACT standard for HCl and, 
for the reasons explained elsewhere, are proposing that the HCl limit 
also serve as a surrogate for other acid gas HAP. We also considered 
whether it was appropriate to exercise our discretionary authority to 
establish health-based emission standards under CAA section 112(d)(4) 
for HCl and each of the other relevant HAP acid gases: Cl2, 
HF, SeO2, and HCN \162\ (because if it were regulated under 
CAA section 112(d)(4), HCl may no longer be the appropriate surrogate 
for these other HAP).\163\ This section sets forth the requirements of 
CAA section 112(d)(4); our analysis of the information available to us 
that informed the decision on whether to exercise discretion; questions 
regarding the application of CAA section 112(d)(4); and our explanation 
of how this case relates to prior decisions EPA has made under CAA 
section 112(d)(4) with respect to HCl.
---------------------------------------------------------------------------

    \162\ Before considering whether to exercise her discretion 
under CAA section 112(d)(4) for a particular pollutant, the 
Administrator must first conclude that a health threshold has been 
established for the pollutant.
    \163\ Hydrogen chloride can serve as a surrogate for the other 
acid gases in a technology-based MACT standard, because the control 
technology that would be used to control HCl would also reduce the 
other acid gases. By contrast, HCl would not be an appropriate 
surrogate for a health-based emission standard that is protective 
against the potential adverse health effects from the other acid 
gases, because these gases (e.g., HF) can act on biological 
organisms in a different manner than HCl, and each of the acid gases 
affects human health with a different dose-response relationship.
---------------------------------------------------------------------------

    As a general matter, CAA section 112(d) requires MACT standards at 
least as stringent as the MACT floor to be set for all HAP emitted from 
major sources. However, CAA section 112(d)(4) provides that for HAP 
with established health thresholds, the Administrator has the 
discretionary authority to consider such health thresholds when 
establishing emission standards under CAA section 112(d). This 
provision is intended to allow EPA to establish emission standards 
other than conventional MACT standards, in cases where a less stringent 
emission standard will still ensure that the health threshold will not 
be exceeded, with an ample margin of safety. In order to exercise this 
discretion, EPA must first conclude that the HAP at issue has an 
established health threshold and must then provide for an ample margin 
of safety when considering the health threshold to set an emission 
standard.
    It is clear the Administrator may exercise her discretionary 
authority under CAA section 112(d)(4) only with respect to pollutants 
with a health threshold. Where there is an established threshold, the 
Administrator interprets CAA section 112(d)(4) to allow her to weigh 
additional factors, beyond any established health threshold, in making 
a judgment whether to set a standard for a specific pollutant based on 
the threshold, or instead follow the traditional path of developing a 
MACT standard after determining a MACT floor. In deciding whether to 
exercise her discretion for a threshold pollutant for a given source 
category, the Administrator interprets CAA section 112(d)(4) to allow 
her to take into account factors such as the following: the potential 
for cumulative adverse health effects due to concurrent exposure to 
other HAP with similar biological endpoints, from either the same or 
other source categories, where the concentration of the threshold 
pollutant emitted from the given source category is below the 
threshold; the potential impacts on ecosystems of releases of the 
pollutant; and reductions in criteria pollutant emissions and other co-
benefits that would be achieved by a MACT standard. Each of these 
factors is directly relevant to the health and environmental outcomes 
at which CAA section 112 is fundamentally aimed. If the Administrator 
does determine that it is appropriate to set a standard based on a 
health threshold, she must develop emission standards that will ensure 
the public will not be exposed to levels of the pertinent HAP in excess 
of the

[[Page 25050]]

health threshold, with an ample margin of safety.
    EPA has exercised its discretionary authority under CAA section 
112(d)(4) in a handful of prior rules setting emissions standards for 
other major source categories, including the Boiler NESHAP issued in 
2004, which was vacated on other grounds by the DC Circuit Court. In 
the Pulp and Paper NESHAP (63 FR 18765; April 15, 1998), and Lime 
Manufacturing NESHAP (67 FR 78054; December 20, 2002), EPA invoked CAA 
section 112(d)(4) for HCl emissions for discrete units within the 
facility. In those rules, EPA concluded that HCl had an established 
health threshold (in those cases it was interpreted as the RfC for 
chronic effects) and HCl was not classified as a human carcinogen. In 
light of the absence of evidence of carcinogenic risk, the availability 
of information on non-carcinogenic effects, and the limited potential 
health risk associated with the discrete units being regulated, EPA 
concluded that it was appropriate to exercise its discretion under CAA 
section 112(d)(4) for HCl under the circumstances of those rules. EPA 
did not set an emission standard based on the health threshold; rather, 
the exercise of EPA's discretion in those cases in effect exempted HCl 
from the MACT requirement. In more recent rules, EPA decided not to 
propose a health-based emission standard for HCl emissions under CAA 
section 112(d)(4) for Portland Cement facilities (75 FR 54970 
(September 9, 2010), and for Industrial, Commercial, and Institutional 
Boilers, (75 FR 32005; June 4, 2010 proposal(major); the final major 
source rule was signed on February 21, 2011 but has not yet been 
published). EPA has never implemented a NESHAP that used CAA section 
112(d)(4) with respect to HF, Cl2, SeO2, or 
HCN.\164\
---------------------------------------------------------------------------

    \164\ EPA has not classified HF, Cl2, 
SeO2, or HCN with respect to carcinogenicity. However, at 
this time the Agency is not aware of any data that would suggest any 
of these HAP are carcinogens.
---------------------------------------------------------------------------

    Because any emission standard under CAA section 112(d)(4) must 
consider the established health threshold level, with an ample margin 
of safety, in this rulemaking EPA has considered the adverse health 
effects of the HAP acid gases, beginning with HCl and including HF, 
Cl2, SeO2, and HCN. Research indicates that HCl 
is associated with chronic respiratory toxicity. In the case of HCl, 
this means that chronic inhalation of HCl can cause tissue damage in 
humans. Among other things, it is corrosive to mucous membranes and can 
cause damage to eyes, nose, throat, and the upper respiratory tract as 
well as pulmonary edema, bronchitis, gastritis, and dermatitis. 
Considering this respiratory toxicity, EPA has established a chronic 
RfC for the inhalation of HCl of 20 micrograms per cubic meter ([mu]g/
m\3\). An RfC is defined as an estimate (with uncertainty spanning 
perhaps an order of magnitude) of a continuous inhalation exposure to 
the human population (including sensitive subgroups \165\) that is 
likely to be without an appreciable risk of deleterious effects during 
a lifetime. The development of the RfC for HCl reflected data only on 
its chronic respiratory toxicity. It did not take into account effects 
associated with acute exposure,\166\ and, in this situation, the IRIS 
health assessment did not evaluate the potential carcinogenicity of HCl 
(on which there are very limited studies). As a reference value for a 
single pollutant, the RfC also did not reflect any potential cumulative 
or synergistic effects of an individual's exposure to multiple HAP or 
to a combination of HAP and criteria pollutants. As the RfC calculation 
focused on health effects, it did not take into account the potential 
environmental impacts of HCl.
---------------------------------------------------------------------------

    \165\ ``Sensitive subgroups'' may refer to particular life 
stages, such as children or the elderly, or to those with particular 
medical conditions, such as asthmatics.
    \166\ California EPA considered acute toxicity and established a 
1-hour reference exposure level (REL) of 2.1 milligrams per cubic 
meter (mg/m\3\). An REL is the concentration level at or below which 
no adverse health effects are anticipated for a specified exposure 
duration. RELs are designed to protect the most sensitive 
individuals in the population by the inclusion of margins of safety.
---------------------------------------------------------------------------

    With respect to the potential health effects of HCl, we note the 
following:
    (1) Chronic exposure to concentrations at or below the RfC is not 
expected to cause chronic respiratory effects;
    (2) Little research has been conducted on its carcinogenicity. The 
one occupational study of which we are aware found no evidence of 
carcinogenicity;
    (3) There is a significant body of scientific literature addressing 
the health effects of acute exposure to HCl (for a summary, see 
California Office of Health Hazard Assessment, 2008. Acute Toxicity 
Summary for Hydrogen Chloride, http://www.oehha.ca.gov/air/hot_spots/2008/AppendixD2_final.pdf#page=112 EPA, 2001). In addition, we note 
that several researchers have shown associations between acid gases and 
reduced lung function and asthma in North American children.\167\ 
However, we currently lack information on the peak short-term emissions 
of HCl from EGUs, which might allow us to determine whether a chronic 
health-based emission standard for HCl would ensure that acute 
exposures will not pose any health concerns, and;
---------------------------------------------------------------------------

    \167\ Dockery DW, Cunningham J, Damokosh AI, Neas LM, Spengler 
JD, Koutrakis P, Ware JH, Raizenne M, Speizer FE. 1996. Health 
Effects of Acid Aerosols on North American Children: Respiratory 
Symptoms. Environmental Health Perspectives 104(5):500-504; Raizenne 
M, Neas LM, Damokosh AI, Dockery DW, Spengler JD, Koutrakis P, Ware 
JH, Speizer FE. 1996. Health Effects of Acid Aerosols on North 
American Children: Pulmonary Function. Environmental Health 
Perspectives 104(5):506-514.
---------------------------------------------------------------------------

    (4) We are aware of no studies explicitly addressing the toxicity 
of mixtures of HCl with other respiratory irritants. However, many of 
the other HAP (and criteria pollutants) emitted by EGUs also are 
respiratory irritants, and in the absence of information on 
interactions, EPA assumes an additive cumulative effect (Supplementary 
Guidance for Conducting Health Risk Assessment of Chemical Mixtures. 
http://cfpub.epa.gov/ncea/cfm/recordisplay.cfm?deid=20533). The fact 
that EGUs can be located in close proximity to a wide variety of 
industrial facilities makes predicting and assessing all possible 
mixtures of HCl and other emitted air pollutants difficult, if not 
impossible.
    In addition to potential health impacts, the Administrator also has 
evaluated the potential for environmental impacts when considering 
whether to exercise her discretion under CAA section 112(d)(4). When 
HCl gas encounters water in the atmosphere, it forms an acidic solution 
of hydrochloric acid. In areas where the deposition of acids derived 
from emissions of sulfur and NOX are causing aquatic and/or 
terrestrial acidification, with accompanying ecological impacts, the 
deposition of hydrochloric acid could exacerbate these impacts. Recent 
research \168\ has suggested that deposition of airborne HCl has had a 
greater impact on ecosystem acidification than previously thought, 
although direct quantification of these impacts remains an uncertain 
process. We maintain it is appropriate to consider potential adverse 
environmental effects in addition to adverse health effects when 
setting an emission standard for HCl under CAA section 112(d)(4).
---------------------------------------------------------------------------

    \168\ Evans, CD, Monteith, DT, Fowler, D, Cape, JN, and 
Brayshaw, S. Hydrochloric Acid: an Overlooked Driver of 
Environmental Change, Env. Sci. Technol., DOI: 10.1021/es10357u.
---------------------------------------------------------------------------

    Because the statute requires an ample margin of safety, it would be 
reasonable to set any CAA section 112(d)(4) emission standard for a 
pollutant with a health threshold at a level that at least

[[Page 25051]]

assures that persons exposed to emissions of the pollutant would not 
experience the adverse health effects on which the threshold is based 
due to sources in the controlled category or subcategory. In the case 
of this proposed rulemaking, we have concluded that we do not have 
sufficient information at this time to establish what the health-based 
emission standards would be for HCl or the other acid gases from EGUs 
alone, much less for EGUs and other sources of acid gas HAP located at 
or near facilities with EGUs.
    Finally, we considered the fact that setting conventional MACT 
standards for HCl as well as PM (as a surrogate for HAP metals) would 
result in significant reductions in emissions of other pollutants, most 
notably SO2, PM, and other non-HAP acid gases (e.g., 
hydrogen bromide) and would likely also result in additional reductions 
in emissions of Hg and other HAP metals (e.g., Se). The additional 
reductions of SO2 alone attributable to the proposed limit 
for HCl are estimated to be 2.1 million tons in the third year 
following promulgation of the proposed HCl standard. These are 
substantial reductions with substantial public health benefits. 
Although NESHAP may directly address only HAP, not criteria pollutants, 
Congress did recognize, in the legislative history to CAA section 
112(d)(4), that NESHAP would have the collateral benefit of controlling 
criteria pollutants as well and viewed this as an important benefit of 
the air toxics program.\169\ Therefore, even where EPA concludes a HAP 
has a health threshold, the Agency may consider the collateral benefits 
of controlling criteria pollutants as a factor in determining whether 
to exercise its discretion under CAA section 112(d)(4).
---------------------------------------------------------------------------

    \169\ See S. Rep. No. 101-228, 101st Cong. 1st sess. At 172.
---------------------------------------------------------------------------

    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 of 
setting a conventional MACT standard for HCl and the other acid gas 
HAP, the Administrator is proposing not to exercise her discretion to 
use CAA section 112(d)(4).
    This conclusion is not contrary to EPA's prior decisions noted 
earlier where we found it appropriate to exercise the discretion to 
invoke the authority in CAA section 112(d)(4) for HCl, because the 
circumstances in this case differ from previous considerations. EGUs 
differ from the other source categories for which EPA has exercised its 
authority under CAA section 112(d)(4) in ways that affect consideration 
of any health threshold for HCl. EGUs are much more likely to be 
significant emitters of acid gas HAP and non-HAP than are other source 
categories. In fact, they are the largest anthropogenic emitter of HCl 
and HF in the U.S, emitting roughly half of the estimated nationwide 
total HCl and HF emissions in 2010. Our case study analyses of the 
chronic impacts of EGUs did not indicate any significant potential for 
them to cause any exceedances of the chronic RfC for HCl due to their 
emissions alone.\170\ However, we do not have adequate information on 
the other acid gas HAP to include them in our analysis, and did not 
consider their impacts in concert with other emitters of HCl (such as 
IB units) to develop estimates of cumulative exposures to HCl and other 
acid gas HAP in the vicinity of EGUs. In addition, EGUs may be located 
at facilities in heavily populated urban areas where many other sources 
of HAP exist. These factors make an analysis of the health impact of 
emissions from these sources on the exposed population significantly 
more complex than for many other source categories, and, therefore, 
make it more difficult to establish an ample margin of safety without 
significantly more information. Absent the information necessary to 
provide a credible basis for developing alternative health-based 
emission standards for all acid gases, and for all the other reasons 
discussed above, EPA is choosing not to exercise its discretion under 
CAA section 112(d)(4) for these pollutants from EGUs.
---------------------------------------------------------------------------

    \170\ For those facilities modeled, the hazard index for HCl 
ranged from 0.05 to 0.005 (see Non-Hg Case Study Chronic Inhalation 
Risk Assessment for the Utility MACT ``Appropriate and Necessary'' 
Analysis in the docket).
---------------------------------------------------------------------------

K. How did we select the compliance requirements?

    We are proposing testing, monitoring, notification, and 
recordkeeping requirements that are adequate to assure continuous 
compliance with the requirements of this proposed rule. These 
requirements are described elsewhere in this preamble. We selected 
these requirements based upon our determination of the information 
necessary to ensure that the emission standards and work practices are 
being followed and that emission control devices and equipment are 
maintained and operated properly. These proposed requirements ensure 
compliance with this proposed rule without imposing a significant 
additional burden for units that must implement them.
    We are proposing that units using continuous monitoring systems for 
PM, HCl, and Hg demonstrate initial compliance by performance testing 
for non-Hg HAP metals and the surrogate PM, for HCl and its surrogate 
SO2, and for Hg, and then to perform subsequent performance 
testing every 5 years for non-Hg HAP metals and PM and for HCl and 
SO2. To ensure continuous compliance with the proposed Hg 
emission limits in-between the performance tests, this proposed rule 
would require coal-fired units to use either CEMS or sorbent trap 
monitoring systems, with an option for very low emitters to use a less 
rigorous method based on periodic stack testing. These requirements are 
found in proposed Appendix A to 40 CFR part 63, subpart UUUUU. For PM 
and HCl, affected units that elect to install CEMS would use the CEMS 
to demonstrate continuous compliance. However, units equipped with 
devices that control PM and HCl emissions but do not elect to use CEMS, 
would determine suitable parameter operating limits, to monitor those 
parameters on a continuous basis, and to conduct emissions testing 
every other month. Units combusting liquid oil on a limited basis 
would, upon request and approval, be allowed to determine limits for 
metals, chlorine, and Hg concentrations in fuel and to measure 
subsequent fuel metals, chlorine, and Hg concentrations monthly; and 
low emitting units would be allowed to determine limits for metals, 
chlorine, and Hg concentrations in fuel and to measure subsequent fuel 
metals, chlorine, and Hg concentrations monthly.
    Additionally, this proposed rule would require annual maintenance 
be performed so that good combustion continues. Such an annual check 
will serve to ensure that dioxins, furans, and other organic HAP 
emissions continue to be at or below MDLs.
    We evaluated the feasibility and cost of applying PM CEMS to EGUs. 
Several electric utility companies in the U.S. have now installed or 
are planning to install PM CEMS. In recognition of the fact that PM 
CEMS are commercially available, EPA developed and promulgated PSs for 
PM CEMS (69 FR 1786, January 12, 2004). Performance Specifications for 
PM CEMS are established under PS 11 in appendix B to 40 CFR part 60 for 
evaluating the acceptability of a PM CEMS used for determining 
compliance with the emission standards on a continuous basis. For PM 
CEMS monitoring, initial costs were estimated to be $261,000 per

[[Page 25052]]

unit and annualized costs were estimated to be $91,000 per unit. We 
determined that requiring PM CEMS for EGUs combusting coal or oil is a 
reasonable monitoring option. We are requesting comment on the 
application of PM CEMS to EGUs, and the use of data from such systems 
for compliance determinations under this proposed rule.
    Table 14 holds preliminary cost information. Note that these costs 
are based on 2010 ICR emissions test estimates and on values in EPA's 
monitoring costs assessment tool. Particulate matter and metals and 
SO2 and HCl testing includes surrogacy testing initially and 
every 5 years, parameter monitoring includes testing every two months, 
and fuel content monitoring includes annual testing.

                                           Table 14--Cost Information
----------------------------------------------------------------------------------------------------------------
                                               Initial costs,     Annual costs,
                                                     $K                $K
----------------------------------------------------------------------------------------------------------------
                                                     Metals
----------------------------------------------------------------------------------------------------------------
PM CEMS.....................................               261                91
Fabric filter...............................                61               109
ESP.........................................                59               114
----------------------------------------------------------------------------------------------------------------
                                                   Acid Gases
----------------------------------------------------------------------------------------------------------------
SO2 CEMS....................................               232                66  None if existing CEMS used.
HCl CEMS....................................               233                57
Dry sorbent injection.......................                10               144  Plus material costs.
Wet scrubber................................                 9               143
----------------------------------------------------------------------------------------------------------------
                                                     Mercury
----------------------------------------------------------------------------------------------------------------
Hg CEMS.....................................               271               110
Sorbent traps...............................                23               128  Minimum of 52 traps and
                                                                                   analysis per year.
Fuel analysis...............................                10                49
----------------------------------------------------------------------------------------------------------------
                                  Dioxin/furan and non-dioxin/furan organic HAP
----------------------------------------------------------------------------------------------------------------
Tune up.....................................                17                 3
----------------------------------------------------------------------------------------------------------------

    The Agency is seeking comment on the cost information presented 
above. The commenters are encouraged to provide detailed information 
and data that will help the Agency refine its cost estimates for this 
rulemaking.
    The majority of test methods that this proposed rule would require 
for the performance stack tests have been required under many other EPA 
standards. Three applicable voluntary consensus standards were 
identified: American Society of Mechanical Engineers (ASME) Performance 
Test Code (PTC) 19-10-1981-Part 10, ``Flue and Exhaust Gas Analyses,'' 
a manual method for measuring the oxygen, CO2, and CO 
content of exhaust gas; ASTM Z65907, ``Standard Method for Both 
Speciated and Elemental Mercury Determination,'' a method for Hg 
measurement; and ASTM Method D6784-02 (Ontario Hydro), a method for 
measuring Hg. The majority of emissions tests upon which the proposed 
emission limitations are based were conducted using these test methods.
    When a performance test is conducted, we are proposing that 
parameter operating limitations be determined during the tests. 
Performance tests to demonstrate compliance with any applicable 
emission limitations are either stack tests or fuel analysis or a 
combination of both.
    To ensure continuous compliance with the proposed emission 
limitations and/or operating limits, this proposed rule would require 
continuous parameter monitoring of control devices and recordkeeping. 
We selected the following requirements based on reasonable cost, ease 
of execution, and usefulness of the resulting data to both the owners 
or operators and EPA for ensuring continuous compliance with the 
emission limitations and/or operating limits.
    We are proposing that certain parameters be continuously monitored 
for the types of control devices commonly used in the industry. These 
parameters include pH, pressure drop and liquid flow rate for wet 
scrubbers; and sorbent injection rate for dry scrubbers and DSI 
systems. You must also install a BLDS for FFs. These monitoring 
parameters have been used in other standards for similar industries. 
The values of these parameters are established during the initial or 
most recent performance test that demonstrates compliance. These values 
are your operating limits for the control device.
    You would be required to set parameters based on 4-hour block 
averages during the compliance test, and demonstrate continuous 
compliance by monitoring 12-hour block average values for most 
parameters. We selected this averaging period to reflect operating 
conditions during the performance test to ensure the control system is 
continuously operating at the same or better level as during a 
performance test demonstrating compliance with the emission limits.
    To demonstrate continuous compliance with the emission and 
operating limits, you would also need daily records of the quantity, 
type, and origin of each fuel burned and hours of operation of the 
affected source. If you are complying with the chlorine fuel input 
option, you must keep records of the calculations supporting your 
determination of the chlorine content in the fuel.
    If a liquid oil-fired EGU elected to demonstrate compliance with 
the HCl or individual or total HAP metal limit by using fuel which has 
a statistically lower pollutant content than the emission limit, we are 
proposing that the source's operating limit is the emission limit of 
the applicable pollutant. Under this option, a source is not required 
to conduct performance

[[Page 25053]]

stack tests. If a source demonstrates compliance with the HCl, 
individual or total PM, or Hg limit by using fuel with a statistically 
higher pollutant content than the applicable emission limit, but 
performance tests demonstrate that the source can meet the emission 
limitations, then the source's operating limits are the operating 
limits of the control device (if used) and the fuel pollutant content 
of the fuel type/mixture burned.
    This proposed rule would specify the testing methodology and 
procedures and the initial and continuous compliance requirements to be 
used when complying with the fuel analysis options. Fuel analysis tests 
for total chloride, gross calorific value, Hg, individual and total HAP 
metal, sample collection, and sample preparation are included in this 
proposed rule.
    If you are a liquid oil-fired EGU and elect to comply based on fuel 
analysis, you will be required to statistically analyze, using the z-
test, the data to determine the 90th percentile confidence level. It is 
the 90th percentile confidence level that is required to be used to 
determine compliance with the applicable emission limit. The 
statistical approach is required to assist in ensuring continuous 
compliance by statistically accounting for the inherent variability in 
the fuel type.
    We are proposing that a source be required to recalculate the fuel 
pollutant content only if it burns a new fuel type or fuel mixture and 
conduct another performance test if the results of recalculating the 
fuel pollutant content are higher than the level established during the 
initial performance test.

L. What alternative compliance provisions are being proposed?

    We are proposing that owners and operators of existing affected 
sources may demonstrate compliance by emissions averaging for units at 
the affected source that are within a single subcategory.
    As part of EPA's general policy of encouraging the use of flexible 
compliance approaches where they can be properly monitored and 
enforced, we are including emissions averaging in this proposed rule. 
Emissions averaging can provide sources the flexibility to comply in 
the least costly manner while still maintaining 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 affected source. 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.
    Emissions averaging would allow owners and operators of an affected 
source to demonstrate that the source complies with the proposed 
emission limits by averaging the emissions from an individual affected 
unit that is emitting above the proposed emission limits with other 
affected units at the same facility that are emitting below the 
proposed emission limits and that are within the same subcategory.
    This proposed rule includes an emissions averaging compliance 
alternative because emissions averaging represents an equivalent, more 
flexible, and less costly alternative to controlling certain emission 
points to MACT levels. We have concluded that a limited form of 
averaging could be implemented that 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.
    EPA has concluded that it is permissible to establish within a 
NESHAP a unified compliance regimen that permits averaging within an 
affected source across individual affected units subject to the 
standard under certain conditions. 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 NESHAP will not be greater under 
the averaging mechanism than it could be if each individual affected 
unit 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 unit, and the statutory requirement 
that the MACT standard reflect the maximum achievable emissions 
reductions is, therefore, fully effectuated.
    In past rulemakings, 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.
    This proposed rule would fully satisfy each of these criteria. 
First, emissions averaging would only be permitted between individual 
sources at a single existing affected source, and would only be 
permitted between individual sources subject to the proposed 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 is consistent with the 
CAA. In addition, this proposed rule would require each facility that 
intends to utilize emission averaging to submit an emission averaging 
plan, which provides additional assurance that the necessary criteria 
will be followed. In this emission 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 
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. Upon receipt, the regulatory 
authority would not be able to approve an emission averaging plan 
containing averaging between emissions of different types of pollutants 
or between sources in different subcategories.
    This proposed rule would also exclude new affected sources from the 
emissions averaging provision. EPA believes emissions averaging is not 
appropriate for new affected sources because it is most cost effective 
to integrate state-of-the-art controls into equipment design and to 
install the technology during construction of new 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. This flexibility is not needed for new affected 
sources because they can be designed and constructed with compliance in 
mind.
    In addition, we seek comment on use of a discount factor when 
emissions averaging is used and on the appropriate value of a discount 
factor, if used. Such discount factors (e.g., 10 percent) have been 
used in previous NESHAP, particularly where there was variation in the 
types of units within a common

[[Page 25054]]

source category to ensure that the environmental benefit was being 
achieved. In this situation, however, the affected sources are more 
homogeneous, making emissions averaging a more straight-forward 
analysis. Further, with the monitoring and compliance provisions that 
are being proposed, there is additional assurance that the 
environmental benefit will be realized. Further, the emissions 
averaging provision would not apply to individual units if the unit 
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.
    The emissions averaging provisions in this proposed 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.\171\
---------------------------------------------------------------------------

    \171\ Hazardous Organic NESHAP (59 FR 19425; April 22, 1994).
---------------------------------------------------------------------------

M. How did EPA determine compliance times for this proposed rule?

    CAA section 112 specifies the dates by which affected sources must 
comply with the emission standards. New or reconstructed units must be 
in compliance with this proposed rule immediately upon startup or [DATE 
THE FINAL RULE IS PUBLISHED IN THE FEDERAL REGISTER], whichever is 
later. Existing sources may be provided up to 3 years to comply with 
the final rule; if an existing source is unable to comply within 3 
years, a permitting authority has the 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. See section 
112(i)(3). We believe that 3 years for compliance is necessary to allow 
adequate time to design, install and test control systems that will be 
retrofitted onto existing EGUs, as well as obtain permits for the use 
of add-on controls.
    We believe that the requirements of the proposed rule can be met 
without adversely impacting electric reliability. Our analysis shows 
that the expected number of retirements is less than many have 
predicted and that these can be managed effectively with existing tools 
and processes for ensuring continued grid reliability. Further, the 
industry has adequate resources to install the necessary controls and 
develop the modest new capacity required within the compliance schedule 
provided for in the CAA. Although there are a significant number of 
controls that need to be installed, with proper planning, we believe 
that the compliance schedule established by the CAA can be met. There 
are already tools in place (such as integrated resource planning, and 
in some cases, advanced auctions for capacity) that ensure that 
companies adequately plan for, and markets are responsive to, future 
requirements such as the proposed rule. In addition, EPA itself has 
already begun reaching out to key stakeholders including not only 
sources with direct compliance obligations, but also groups with 
responsibility to assure an affordable and reliable supply of 
electricity including state Public Utility Commissions (PUC), Regional 
Transmission Organizations (RTOs), the National Electric Reliability 
Council (NERC), the Federal Energy Regulatory Commission (FERC), and 
DOE. EPA intends to continue these efforts during both the development 
and implementation of this proposed rule. It is EPA's understanding 
that FERC and DOE will work with entities whose responsibility is to 
ensure an affordable, reliable supply of electricity, including state 
PUCs, RTOs, the NERC to share information and encourage them to begin 
planning for compliance and reliability as early as possible. This 
effort to identify and respond to any projected local and regional 
reliability concerns will inform decisions about the timing of 
retirements and other compliance strategies to ensure energy 
reliability. EPA believes that the ability of permitting authorities to 
provide an additional 1 year beyond the 3-year compliance time-frame as 
specified in CAA section 112, along with other compliance tools, 
ensures that the emission reductions and health benefits required by 
the CAA can be achieved while safeguarding completely against any risk 
of adverse impacts on electricity system reliability. Between proposal 
and final, EPA will work with DOE and FERC to identify any 
opportunities offered by the authorities and policy tools at the 
disposal of DOE and/or FERC that can be pursued to further ensure that 
the dual goals of substantially reducing the adverse public health 
impacts of power generation, as required by the CAA, while continuing 
to assure electric reliability is maintained. EPA also intends to 
continue to work with DOE, FERC, state PUCs, RTOs and power companies 
as this rule is implemented to identify and address any challenges to 
ensuring that both the requirements of the CAA and the need for a 
reliable electric system are met.
    In developing this proposed rule, EPA has performed specific 
analysis to assess the feasibility (e.g., ability of companies to 
install the required controls within the compliance time-frame) and 
potential impact of the proposed rule on reliability.
    With regards to feasibility, EPA used IPM to project what types of 
controls would need to be installed to meet the requirements of this 
proposed rule. This includes technologies to control acid gases (wet 
and dry scrubber technology and the use of sorbent injection), the Hg 
requirements (co-benefits from other controls such as scrubbers and FFs 
and Hg-specific controls such as ACI), the non-Hg metal requirements 
(upgrades and or replacements of existing particulate control devices), 
and other HAP emissions (GCP).
    Much of the power sector already has controls in place that remove 
significant amounts of acid gases. Today over 50 percent of the power 
generation fleet has scrubbing technology installed and the industry is 
already working on installations to bring that number to nearly two-
thirds of the fleet by 2015. Many of the remaining coal-fired units are 
smaller, burn lower sulfur coals, and/or do not operate in a base-load 
mode. Units with these types of characteristics are candidates to use 
DSI technology which takes significantly less time to install. Units 
that choose to install dry or wet scrubbing technology should be able 
to do so within the compliance schedule required by the CAA as this 
technology can be installed within the 3-year window.\172\ Notably, EPA 
does not project use of wet scrubbing technology to meet the 
requirements of this proposed rule and that is the technology that 
typically takes a longer time to install.
---------------------------------------------------------------------------

    \172\ In a letter to Senator Carper dated November 3, 2010 
(http://www.icac.com/files/public/ICAC_Carper_Response_110310.pdf) David Foerter, the executive director of the Institute 
of Clean Air Companies (ICAC) explained that wet scrubber technology 
could be installed in 36 months, dry scrubber technology could be 
installed in 24 months and dry sorbent injection could be installed 
in 12 months. Page 3.
---------------------------------------------------------------------------

    For Hg control, those units that do not meet the requirements with 
existing controls have several options. Companies with installed 
scrubbers may be able to make modifications (such as the use of 
scrubber additives to enhance Hg control). Other companies may use 
supplemental controls such as ACI. These types of options all take 
significantly less than 3 years to install.
    Units that do not meet the non-Hg metal HAP requirements have 
several options such as upgrading existing particulate controls, 
installing

[[Page 25055]]

supplemental particulate controls, or replacing existing particulate 
controls. These options can also be implemented in significantly less 
than 3 years.
    EPA projects that for acid gas control, companies will likely use 
dry scrubbing and sorbent injection technologies rather than wet 
scrubbing. For non-Hg metal HAP controls, EPA has assumed that 
companies with ESPs will likely upgrade them to FFs. As a number of 
units that were in the MACT floor for non-Hg HAP metals only had ESPs 
installed, this is likely a conservative assumption. For Hg, EPA 
projects that companies will comply through either the collateral 
reductions created by other controls (e.g., scrubber/SCR combination) 
or ACI. EPA has assessed the feasibility of installing these controls 
within the compliance window (see TSD) and believes that the controls 
can be reasonably installed within that time. Although EPA assessed the 
ability to install the controls in 3 years (and determined that the 
controls could be installed in that time-frame), this would require the 
control technology industry to ramp up quickly. Therefore, EPA also 
assessed a time-frame that would allow some installations to take up to 
4 years. This time-frame is consistent with the CAA which allows 
permitting authorities the discretion to grant extensions to the 
compliance time-line of up to 1 year. This time-frame also allows for 
staggered installation of controls at facilities that need to install 
technologies on multiple units. Staggered installation allows companies 
to address such issues as scheduling outages at different units so that 
reliable power can be provided during these outage periods or 
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). In other words, the additional 1-year extension would provide an 
additional two shoulder periods to schedule outages. It also provides 
additional opportunity to spread complex outages over multiple outage 
periods. EPA believes that while many units will be able to fully 
comply within 3 years, the 4th 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.
    Permitting authorities are familiar with the operation of this 
provision because they have used it in implementing previous NESHAP. 
This extension can be used to address a range of reasons that 
installation schedules may take more than 3 years including: staggering 
installations for reliability or constructability purposes, or other 
site-specific challenges that may arise related to source-specific 
construction issues, permitting, or local manpower or resource 
challenges. EPA is proposing that States consider applying this 
extension both to the installation of add on controls (e.g., a FF, or a 
dry scrubber) and the construction of on-site replacement power (e.g., 
a case when a coal 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 and the replacement process requires more than 
3 years to accomplish). EPA believes that it is reasonable to allow the 
extension to apply to the replacement because EPA believes that 
building of replacement power could be considered ``installation of 
controls'' at the facility. Because the phrase ``installation of 
controls'' could also be interpreted to apply only to changes made to 
an existing unit rather than the replacement of that existing unit with 
a new cleaner one, EPA takes comment on its proposal to allow the 
extension to apply to replacement power.
    EPA has also considered the impact that potential retirements under 
this proposed rule will have on reliability. 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 electric demand, cost of 
alternative generation, and cost of continuing to generate using an 
existing unit. EPA's analysis shows that the lower cost of alternative 
generating sources (particularly the cost of natural gas), as well as 
reductions in demand, have a greater impact on the number of projected 
retirements than does the impact of the proposed rule. EPA's assessment 
looked at the reserve margins in each of 32 subregions in the 
continental U.S. It shows that with the addition of very little new 
capacity, average reserve margins are significantly higher than 
required (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 transmission constraints, the number of 
retirements projected suggests that the magnitude of any local 
retirements should be manageable with existing tools and processes. 
Demand forecasts used were based on EIA projected demand growth.
    Reliability concerns caused by local transmission constraints can 
be addressed through a range of solutions including the development of 
new generation and/or demand side resources, and/or enhancements to the 
transmission system. 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 large reserve margins, there are 
companies ready to implement supply side projects quickly. For 
instance, in the PJM Interconnection (an RTO) region, there are over 
11,600 MW of capacity that have completed feasibility and impact 
studies and could be on-line by the third quarter of 2014.\173\ 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 Interconnection 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.\174\ Recent experience also shows that 
transmission upgrades to address reliability issues from plant closures 
can also occur in less than 3 years. 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.
---------------------------------------------------------------------------

    \173\ 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.
    \174\ Ibid--slide 5.
---------------------------------------------------------------------------

    EPA also examined the impact on reliability of unit outages to 
install control equipment. Because these outages usually occur in the 
shoulder months (outside summer or winter peaking periods) when demand 
is lower (and, thus, reserve margins are higher), the analysis showed 
that even with conservative estimates regarding the length of the 
outages and conservative estimates about how many outages occurred 
within a 1-year time-frame, reserve margins were maintained. With the 
potential for a 1-year compliance extension, outages can be further 
staggered, providing additional flexibility, even if some units require 
longer outages.
    Although EPA's analysis shows that there is sufficient time and 
grid capacity to allow for compliance with the rule within the 3-year 
compliance window

[[Page 25056]]

(with the possibility of a 1-year extension), to achieve compliance in 
a timely fashion, EPA expects that sources will begin promptly, based 
upon this proposed rule, to evaluate, select, and plan to implement, 
source-specific compliance options. In doing so, we would expect 
sources to consider the following factors: if retirement is the 
selected compliance option, notifying any relevant RTO/ISO in advance 
in order to develop an appropriate shutdown plan that identifies any 
necessary replacement power transmission upgrades or other actions 
necessary to ensure consistent electric supply to the grid; if 
installation of control technologies is necessary, any source-specific 
space limitations, such that installation can be staggered in a timely 
fashion; and source-specific electric supply requirements, such that 
outages can be appropriately scheduled. Starting assessments early and 
considering the full range of options is prudent because it will help 
ensure that the requirements of this proposed rule are met as 
economically as possible and that power companies are able to provide 
reliable electric power.
    There is significant evidence that companies do in fact engage in 
such forward planning. For instance, in September of 2004 
(approximately 6 months before the CAIR and CAMR requirements were 
finalized); Cinergy announced that it had already begun a construction 
program to comply. This program involved not only preliminary 
engineering, but actual construction of scrubbers.\175\ Southern 
Company also began its engineering process well before those rules were 
finalized.\176\ Although EPA understands that not every generating 
company may commit to actual capital projects in advance of 
finalization of the rule, the CAIR experience shows that some companies 
do. Even if companies do not take the step of committing to the capital 
projects, there are actions that companies can take that are much less 
costly. Companies can analyze their unit-by-unit compliance options 
based on the proposed rule. This will put them in a position to begin 
construction of projects with the longest lead times quickly and will 
ensure that the 3-year compliance window (or 4 with extension from the 
permitting authority) can be met.
---------------------------------------------------------------------------

    \175\ Cinergy Press Release, September 2nd, 2004, ``Cinergy 
Operating Companies to Reduce Power Plant Emissions, Improve Air 
Quality.''
    \176\ ICAC.
---------------------------------------------------------------------------

    It will also ensure that sufficient notification can be provided to 
RTOs/ISOs so that the full range of options for addressing any 
reliability concerns can be considered. Although most RTOs/ISOs only 
require 90-day notifications for retirements, construction schedules 
for all but the simplest retrofits will be longer, so sources should be 
able to notify their RTOs of their retirements earlier. This will also 
help as multiple sources work with their RTO/ISO to determine outage 
schedules. The RTOs/ISOs also have a very important role to play and it 
appears that a number of them are already engaged in preparing for 
these rules. For instance, PJM Interconnection considered the impact of 
these anticipated rules at its January 14, 2011, Regional Planning 
Process Task Force Meeting,\177\ and Midwest Independent Transmission 
System Operator, Inc. (MISO) has also begun a planning process to 
consider the impact of EPA rules.\178\
---------------------------------------------------------------------------

    \177\ Paul M Sotkiewicz, PJM Interconnection, ``Consideration of 
Forthcoming Environmental Regulations in the Planning Process,'' 
January 14, 2011.
    \178\ MISO Planning Advisory Committee, ``Proposed EPA 
Regulatory Impact Analysis,'' November 23, 2010.
---------------------------------------------------------------------------

    As discussed above, given the large reserve margins that exist, 
even after consideration of requirements of the proposed rule, EPA 
believes that any reliability issues are likely to be primarily local 
in nature and be due to the retirement of a unit in a load constrained 
area. As demonstrated by the work that PJM Interconnection and MISO are 
doing, RTOs/ISOs are required to do long range (at least 10 years) 
capacity planning that includes consideration of future requirements 
such as EPA regulations. Furthermore, if companies within an RTO/ISO 
wish to retire a unit, they must first notify the RTO/ISO in advance so 
that any reliability concerns can be addressed. The RTOs/ISOs, have 
well established procedures to address such retirements.
    Starting assessments early and considering the full range of 
options will help ensure that the requirements of this rule are met as 
economically as possible and that power companies are able to provide 
reliable electric power while significantly reducing their impact on 
public health. For power companies this includes considering the range 
of pollution control options available for their existing fleet as well 
as considering the range of options for replacement power, in the cases 
where shutting down a unit is the more economic choice. The RTOs/ISOs 
should consider the full range of options to provide any necessary 
replacement power including the development of both supply and demand 
side resources. Environmental regulators should work with their 
affected sources early to understand their compliance choices. In this 
way, those regulators will be able to accurately access when use of the 
1-year compliance extension is appropriate. By working with regulators 
early, affected sources will be in a position to have assurance that 
the 1-year extension will be granted in those situations where it is 
appropriate.
    Section X.c. describes the sensitivity analysis performed by EPA 
for an Energy Efficiency case, in which a combination of DOE appliance 
standards and State investments in demand-side efficiency come into 
place at the same time as compliance with the requirements of this 
rule. That analysis shows that even in the absence of this rule, 
moderate actions to promote energy efficiency would lead to retirement 
of an additional 11 GW in 2015, of 27 GW in 2020, and of 26 GW in 2030, 
beyond the capacity already projected to retire in the base case. In 
effect, the timely adoption and implementation of energy efficiency 
policies would augment currently projected reserve capacities that are 
instrumental to assuring system reliability.
    As noted, instrumental to undertaking such actions are other 
Federal agencies such as DOE, ISOs and RTOs, and state agencies such as 
PUCs. Fortunately, in addition to helping to assure system reliability, 
timely implementation of energy efficiency policies offer these key 
decision-makers an additional incentive to take action. As the analysis 
shows, energy efficiency can reduce costs for ratepayers and customers.
    First, with or without the proposed Toxic Rule, energy efficiency 
policies are shown by the analysis to reduce the overall costs of 
generating electricity, with the cost reductions increasing over time. 
See Table 22. Second, when comparing the Toxics Rule Case without 
energy efficiency to the Toxics Rule Case with energy efficiency, the 
analysis suggests that if these energy efficiency policies were to be 
put into place and maintained over time by system operators, states and 
DOE, the costs of the proposed Toxics Rule are mitigated by these cost 
reductions such that the overall system costs are reduced by $2 billion 
in 2015, $6 billion in 2020, and $11 billion in 2030.
    The energy savings driven by these energy efficiency policies mean 
that consumers will pay less for electricity as well. EPA has modeled 
national average retail electricity prices, including the energy 
efficiency costs that are paid by the ratepayer. The Toxics Rule 
increases retail prices by 3.7 percent, 2.6 percent and 1.9 percent in 
2015, 2020 and 2030

[[Page 25057]]

respectively relative to the base case. If energy efficiency policies 
are implemented along with the Toxics Rule, the average retail price of 
electricity increases by 3.3 percent in 2015 relative to the base case, 
but falls relative to the base case by about 1.6 percent in 2020 and 
about 2.3 percent in 2030. The effect on electricity bills however may 
fall more than these percentages suggest as energy efficiency means 
that less electricity will be used by consumers of electricity.
    EPA believes that as it shares these results with PUCs, the 
commissions will respond in accordance with their ongoing imperative to 
ensure that electricity costs for ratepayers and consumers remains 
stable. Specifically, the opportunity created through the deployment of 
energy efficiency-promoting strategies and initiatives to safeguard 
system reliability and, especially, to curb cost increases that might 
otherwise result from implementation of the Toxics Rule should provide 
PUCs with both the motivation and the justification for providing 
utilities with the financial and regulatory support they need to begin 
planning as early as possible for compliance and to incorporate in 
their plans the kinds of energy efficiency investments needed to 
achieve both compliance and cost-minimization.
    EPA recognizes that both utilities and their regulators often are 
hesitant to take early action to comply with environmental standards 
because they avoid incurring costs that they fear may not be required 
once the final regulation is promulgated. EPA urges utilities and 
regulators to begin planning and preparations for timely compliance. 
The same concerns about consumer cost in some cases also dissuade 
utilities from incurring, and commissions from authorizing, the upfront 
costs associated with energy efficiency programs. However, EPA also 
believes that if it takes steps to actively disseminate the results of 
the energy efficiency analysis, then utilities will be that much more 
likely to begin, and regulators that much more likely to support, 
comprehensive assessment and planning as early as possible since 
compliance approaches that encompass energy efficiency integrated with 
other actions needed to meet the Toxics Rule's requirements will result 
in lower costs for ratepayers and consumers. EPA encourages State 
environmental regulators to consider the extent to which a utility 
engages in early planning when making a decision regarding granting a 
4th year for compliance with the Toxics Rule.
    In summary, EPA believes that the large reserve margins, the range 
of control options, the range of flexibilities to address unit 
shutdowns, existing processes to assure that sufficient generation 
exists when and where it is needed, and the flexibilities within the 
CAA, provide sufficient assurance that the CAA section 112 requirements 
for the power sector can be met without adversely impacting electric 
reliability.
    EGUs are the subject of several rulemaking efforts that either are 
or will soon be underway. In addition to this rulemaking proposal, 
concerning both hazardous air pollutants under section 112 and criteria 
pollutant NSPS standards under section 111, EGUs are the subject of 
other rulemakings, including ones under section 110(a)(2)(D) addressing 
the interstate transport of emissions contributing to ozone and PM air 
quality problems, coal combustion wastes, and the implementation of 
section 316(b) of the Clean Water Act (CWA). They will also soon be the 
subject of a rulemaking under CAA section 111 concerning emissions of 
greenhouse gases.
    EPA recognizes that it is important that each and all of these 
efforts achieve their intended environmental objectives in a common-
sense manner that allows the industry to comply with its obligations 
under these rules as efficiently as possible and to do so by making 
coordinated investment decisions and, to the greatest extent possible, 
by adopting integrated compliance strategies. 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.'' Thus, EPA recognizes that it 
needs to approach these rulemakings, to the extent that its legal 
obligations permit, 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 the rulemakings must 
achieve.
    The upcoming rulemaking under section 111 regarding GHG emissions 
from EGUs may provide an opportunity to facilitate the industry's 
undertaking integrated compliance strategies in meeting the 
requirements of these rulemakings. First, since that rulemaking will be 
finalized after a number of the other rulemakings that are currently 
underway are, the Agency will have an opportunity to take into account 
the effects of the earlier rulemakings in making decisions regarding 
potential GHG standards for EGUs.
    Second, in that rulemaking, EPA will be addressing both CAA section 
111(b) standards for emissions from new and modified EGUs and CAA 
section 111(d) emission guidelines for states to follow in establishing 
their plans regarding GHG emissions from existing EGUs. In evaluating 
potential emission standards and guidelines, EPA may consider the 
impacts of other rulemakings on both emissions of GHGs from EGUs and 
the costs borne by EGUs. The Agency expects to have ample latitude to 
set requirements and guidelines in ways that can support the states' 
and industry's efforts in pursuing practical, cost-effective and 
coordinated compliance strategies encompassing a broad suite of its 
pollution-control obligations. EPA will be taking public comment on 
such flexibilities in the context of that rulemaking.
    As discussed elsewhere in this preamble, we invite comment on this 
proposed rule. EPA solicits comment on the ability of sources subject 
to this proposed rule to comply within the statutorily mandated 3-year 
compliance window and/or the 1-year discretionary extension, as well as 
comment on specific factors that could prevent a source from achieving, 
or could enable a source to achieve, compliance. In addition, EPA 
requests comment on the impact of this proposed rule on electric 
reliability, and ways to ensure compliance while maintaining the 
reliability of the grid.
    A number of states (or localities) have proactively developed plans 
to address a suite of environmental issues, an aging generation fleet, 
and electric reliability (e.g., plans requiring retirement of coal and 
pollution control devices such as the Colorado ``Clean Air-Clean Jobs 
Act'' or renewable portfolio standards that because of the states' 
current generation mix could result in significant changes to the 
composition of the fossil-fuel-fired portion of the fleet such as 
Hawaii's renewable portfolio standard (HB-1464)). In most cases, these 
plans were developed solely under State law with no underlying Federal 
requirement. Furthermore, as explained above, many of the technologies 
that were installed or that are planned to be installed in response to 
these state plans are likely to result in collateral reductions of many 
HAP required to be reduced in today's proposed rule. Although some of 
these state programs may have obtained some important emission 
reductions to date, they may also allow compliance time-frames for

[[Page 25058]]

some units that extend beyond those authorized under CAA section 
112(i)(3).
    The Agency has a program pursuant to 40 CFR subpart E, whereby 
states can take delegation of section 112 emission standards. Among 
other things, states can seek approval of state rules to the extent 
they can demonstrate that those rules are no less stringent that the 
applicable section 112(d) rule. Because overall, some of these state 
programs may result in greater emission reductions, EPA is taking 
comment on whether (and if so how) such state plans could be integrated 
with the proposed rule requirements consistent with the statute. EPA 
also intends to engage with states who believe that they have such 
plans to understand whether they believe that there are opportunities 
to integrate the two sets of requirements in a manner consistent with 
the requirements of the CAA.
    EGUs are the subject of several rulemaking efforts that either are 
or will soon be underway. In addition to this rulemaking proposal, 
concerning both HAP under section 112 and criteria pollutant NSPS 
standards under section 111, EGUs are the subject of other rulemakings, 
including ones under section 110(a)(2)(D) addressing the interstate 
transport of emissions contributing to ozone and PM air quality 
problems, coal combustion wastes, and the implementation of section 
316(b) of the CWA. They will also soon be the subject of a rulemaking 
under CAA section 111 concerning emissions of greenhouse gases (GHG).
    EPA recognizes that it is important that each and all of these 
efforts achieve their intended environmental objectives in a common-
sense manner that allows the industry to comply with its obligations 
under these rules as efficiently as possible and to do so by making 
coordinated investment decisions and, to the greatest extent possible, 
by adopting integrated compliance strategies. Thus, EPA recognizes that 
it needs to approach these rulemakings, to the extent that its legal 
obligations permit, 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 the rulemakings must 
achieve.
    The upcoming rulemaking under section 111 regarding GHG emissions 
from EGUs may provide an opportunity to facilitate the industry's 
undertaking integrated compliance strategies in meeting the 
requirements of these rulemakings. First, since that rulemaking will be 
finalized after a number of the other rulemakings that are currently 
underway are, the agency will have an opportunity to take into account 
the effects of the earlier rulemakings in making decisions regarding 
potential GHG standards for EGUs.
    Second, in that rulemaking, EPA will be addressing both CAA section 
111(b) standards for emissions from new and modified EGUs and CAA 
section 111(d) emission guidelines for states to follow in establishing 
their plans regarding GHG emissions from existing EGUs. In evaluating 
potential emission standards and guidelines, EPA may consider the 
impacts of other rulemakings on both emissions of GHGs from EGUs and 
the costs borne by EGUs. The Agency expects to have ample latitude to 
set requirements and guidelines in ways that can support the states' 
and industry's efforts in pursuing practical, cost-effective and 
coordinated compliance strategies encompassing a broad suite of its 
pollution-control obligations. EPA will be taking public comment on 
such flexibilities in the context of that rulemaking.

N. How did EPA determine the required records and reports for this 
proposed rule?

    You would be required to comply with the applicable requirements in 
the NESHAP General Provisions, subpart A of 40 CFR part 63, as 
described in Table 10 of the proposed 40 CFR part 63, subpart UUUUU. We 
evaluated the General Provisions requirements and included those we 
determined to be the minimum notification, recordkeeping, and reporting 
requirements necessary to ensure compliance with, and effective 
enforcement of, this proposed rule.
    We would require additional recordkeeping if you chose to comply 
with the chlorine or Hg fuel input option. You would need to keep 
records of the calculations and supporting information used to develop 
the chlorine or Hg fuel input operating limit.

O. How does this proposed rule affect permits?

    The CAA requires that sources subject to this proposed rule be 
operated pursuant to a permit issued under EPA-approved state operating 
permit program. The operating permit programs are developed under Title 
V of the CAA and the implementing regulations under 40 CFR parts 70 and 
71. If you are operating in the first 2 years of the current term of 
your operating permit, you will need to obtain a revised permit to 
incorporate this proposed rule. If you are in the last 3 years of the 
current term of your operating permit, you will need to incorporate 
this proposed rule into the next renewal of your permit.

P. Alternative Standard for Consideration

    As discussed above, we are proposing alternate equivalent emission 
standards (for certain subcategories) to the proposed surrogate 
standards in three areas: SO2 (in addition to HCl), 
individual non-Hg metals (for PM), and total non-Hg metals (for PM). 
The proposed emission limitations are provided in Tables 16 and 17 of 
this preamble.

                                     Table 15--Alternate Emission Limitations for Existing Coal- and Oil-Fired EGUs
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                         Coal-fired unit
                                     designed for coal  = 8,300 Btu/lb   designed for coal  <            GWh)                 (lb/GWh)          Solid oil-derived
                                                                  8,300 Btu/lb
--------------------------------------------------------------------------------------------------------------------------------------------------------
SO2................................  0.20 lb/MMBtu (2.0 lb/  0.20 lb/MMBtu (2.0 lb/  NA...................  NA...................  0.40 lb/MMBtu (5.0 lb/
                                      MWh).                   MWh).                                                                 MWh).
Total non-Hg metals................  0.000040 lb/MMBtu       0.000040 lb/MMBtu       5.0 (0.050)..........  NA...................  0.000050 lb/MMBtu
                                      (0.00040 lb/MWh).       (0.00040 lb/MWh).                                                     (0.001 lb/MWh).
Antimony, Sb.......................  0.60 lb/TBtu (0.0060    0.60 lb/TBtu (0.0060    0.40 (0.0040)........  0.20 (0.0030)........  0.40 lb/TBtu (0.0070
                                      lb/GWh).                lb/GWh).                                                              lb/GWh).
Arsenic, As........................  2.0 lb/TBtu (0.020 lb/  2.0 lb/TBtu (0.020 lb/  2.0 (0.020)..........  0.60 (0.0070)........  0.40 lb/TBtu (0.0040
                                      GWh).                   GWh).                                                                 lb/GWh).
Beryllium, Be......................  0.20 lb/TBtu (0.0020    0.20 lb/TBtu (0.0020    0.030 (0.0030).......  0.060 (0.00070)......  0.070 lb/TBtu
                                      lb/GWh).                lb/GWh).                                                              (0.00070 lb/GWh).
Cadmium, Cd........................  0.30 lb/TBtu (0.0030    0.30 lb/TBtu (0.0030    0.20 (0.0020)........  0.10 (0.0020)........  0.40 lb/TBtu (0.0040
                                      lb/GWh).                lb/GWh).                                                              lb/GWh).

[[Page 25059]]

 
Chromium, Cr.......................  3.0 lb/TBtu (0.030 lb/  3.0 lb/TBtu (0.030 lb/  3.0 (0.020)..........  2.0 (0.020)..........  2.0 lb/TBtu (0.020 lb/
                                      GWh).                   GWh).                                                                 GWh).
Cobalt, Co.........................  0.80 lb/TBtu (0.0080    0.80 lb/TBtu (0.0080    2.0 (0.0040).........  3.0 (0.020)..........  2.0 lb/TBtu (0.020 lb/
                                      lb/GWh).                lb/GWh).                                                              GWh).
Lead, Pb...........................  2.0 lb/TBtu (0.020 lb/  2.0 lb/TBtu (0.020 lb/  0.0002 lb/MMBtu        2.0 (0.030)..........  11.0 lb/TBtu (0.020
                                      GWh).                   GWh).                   (0.003 lb/MWh).                               lb/GWh).
Manganese, Mn......................  5.0 lb/TBtu (0.050 lb/  5.0 lb/TBtu (0.050 lb/  3.0 (0.020)..........  5.0 (0.060)..........  3.0 lb/TBtu (0.040 lb/
                                      GWh.                    GWh.                                                                  GWh).
Mercury, Hg........................  NA....................  NA....................  NA...................  0.050 lb/TBtu          NA.
                                                                                                             (0.00070 lb/GWh).
Nickel, Ni.........................  4.0 lb/TBtu (0.040 lb/  4.0 lb/TBtu (0.040 lb/  5.0 (0.050)..........  8.0 (0.080)..........  9.0 lb/TBtu (0.090 lb/
                                      GWh).                   GWh).                                                                 GWh).
Selenium, Se.......................  6.0 lb/TBtu (0.060 lb/  6.0 lb/TBtu (0.060 lb/  22.0 (0.20)..........  2.0 (0.020)..........  2.0 lb/TBtu (0.020 lb/
                                      GWh).                   GWh).                                                                 GWh).
--------------------------------------------------------------------------------------------------------------------------------------------------------
NA = Not applicable.


                                        Table 16--Alternate Emission Limitations for New Coal- and Oil-Fired EGUs
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                         Coal-fired unit
                                     designed for coal  = 8,300 Btu/lb   designed for coal  <           IGCC *           Liquid oil, lb/GWh     Solid oil-derived
                                                                  8,300 Btu/lb
--------------------------------------------------------------------------------------------------------------------------------------------------------
SO2................................  0.40 lb/MWh...........  0.40 lb/MWh...........  0.40 lb/MWh..........  NA...................  0.40 lb/MWh.
Total metals.......................  0.000040 lb/MWh.......  0.000040 lb/MWh.......  0.000040 lb/MWh......  NA...................  0.00020 lb/MWh.
Antimony, Sb.......................  0.000080 lb/GWh.......  0.000080 lb/GWh.......  0.000080 lb/GWh......  0.0020...............  0.00090 lb/GWh.
Arsenic, As........................  0.00020 lb/GWh........  0.00020 lb/GWh........  0.00020 lb/GWh.......  0.0020...............  0.0020 lb/GWh.
Beryllium, Be......................  0.000030 lb/GWh.......  0.000030 lb/GWh.......  0.000030 lb/GWh......  0.00070..............  0.000080 lb/GWh.
Cadmium, Cd........................  0.00040 lb/GWh........  0.00040 lb/GWh........  0.00040 lb/GWh.......  0.00040..............  0.0070 lb/GWh.
Chromium, Cr.......................  0.020 lb/GWh..........  0.020 lb/GWh..........  0.020 lb/GWh.........  0.020................  0.0060 lb/GWh.
Cobalt, Co.........................  0.00080 lb/GWh........  0.00080 lb/GWh........  0.00080 lb/GWh.......  0.0060...............  0.0020 lb/GWh.
Lead, Pb...........................  0.00090 lb/GWh........  0.00090 lb/GWh........  0.00090 lb/GWh.......  0.0060...............  0.020 lb/GWh.
Mercury, Hg........................  NA....................  NA....................  NA...................  0.00010 lb/GWh.......  NA.
Manganese, Mn......................  0.0040 lb/GWh.........  0.0040 lb/GWh.........  0.0040 lb/GWh........  0.030................  0.0070 lb/GWh.
Nickel, Ni.........................  0.0040 lb/GWh.........  0.0040 lb/GWh.........  0.0040 lb/GWh........  0.040................  0.0070 lb/GWh.
Selenium, Se.......................  0.030 lb/GWh..........  0.030 lb/GWh..........  0.030 lb/GWh.........  0.0040...............  0.00090 lb/GWh.
--------------------------------------------------------------------------------------------------------------------------------------------------------
* Beyond-the-floor as discussed elsewhere.
NA = Not applicable.

    Most, if not all, coal-fired EGUs and solid oil-derived fuel-fired 
EGUs already have emission limitations for SO2 under either 
the Federal NSPS, individual SIP programs, or the Federal ARP and, as a 
result, have SO2 emission controls installed. Further, again 
most, if not all, coal-fired EGUs have SO2 CEMS installed 
and operating under the provisions of one of these programs. Thus, as 
SO2 is a suitable surrogate for the acid gas HAP, it could 
be used as an alternate equivalent standard to the HCl standard for 
EGUs with FGD systems installed and operated at normal capacity. An 
SO2 standard would ensure that equivalent control of the 
acid gas HAP is achieved, and some facilities may find it preferable to 
use the existing SO2 CEMS for compliance purposes rather 
than having to perform the manual HCl compliance testing. As noted 
elsewhere, this approach does not work for EGUs that do not have 
SO2 controls installed and, thus, those EGUs may not utilize 
the alternate SO2 limitations. Further, no SO2 
data were provided by the two IGCC units; therefore, there is no 
alternative SO2 limitation being proposed for existing IGCC 
units.
    Some sources have expressed a preference for individual non-Hg 
metal HAP emission limitations rather than the use of PM as a 
surrogate. Thus, EPA has analyzed the data for that purpose and we are 
proposing both alternate individual HAP metal limitations and total HAP 
metal limitations for all subcategories except liquid oil-fired EGUs. 
These limitations provide equivalent control of metal HAP as the 
proposed PM limitations.
    We are soliciting comments on all aspects of these alternate 
emission limitations.

VI. Background Information on the Proposed NSPS

A. What is the statutory authority for this proposed NSPS?

    New source performance standards implement CAA section 111(b), and 
are issued for source categories which EPA has determined cause, or 
contribute significantly to, air pollution which may reasonably be 
anticipated to endanger public health or welfare. CAA section 
111(b)(1)(B) requires the EPA to periodically review and, if 
appropriate, revise the NSPS to reflect improvements in emissions 
reduction methods.
    CAA section 111 requires that the NSPS reflect the application of 
the best system of emissions reductions which the Administrator 
determines has been adequately demonstrated (taking into account the 
cost of achieving such reduction, any non-air quality health and 
environmental impacts and energy requirements). This level of control 
is commonly referred to as best demonstrated technology (BDT).

[[Page 25060]]

    The current standards for steam generating units are contained in 
the NSPS for electric utility steam generating units (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). 
Previous standards that continue to apply to owners/operators of 
existing affected facilities, but which have been superseded for owner/
operators of new affected facilities, are contained in the NSPS for 
fossil-fuel-fired steam generating units for which construction was 
commenced after August 17, 1971, but on or before September 18, 1978 
(40 CFR part 60, subpart D).

B. Summary of State of New York, et al., v. EPA Remand

    On February 27, 2006, EPA promulgated amendments to the NSPS for 
EGUs (40 CFR part 60, subpart Da) which established new standards for 
PM, SO2, and NOX (71 FR 9,866). EPA was 
subsequently sued on the amendments by multiple state governments, 
municipal governments, and environmental organizations (collectively 
the Petitioners). State of New York v. EPA, No. 06-1148 (DC Cir.). The 
Petitioners alleged that EPA failed to correctly identify the best 
system of emission reductions for the newly established SO2 
and NOX standards. The Petitioners also contended that EPA 
was required to establish separate emission limits for fine filterable 
PM (PM2.5) and condensable PM. Finally, the petitioners 
claimed the NSPS failed to reflect the degree of emission limitation 
achievable through the application of IGCC technology. Based upon 
further examination of the record, EPA determined that certain issues 
in the rule warranted further consideration. On that basis, EPA sought 
and, on September 4, 2009, was granted a voluntary remand without 
vacatur of the 2006 amendments.

C. EPA's Response to the Remand

    The emission standards established by the 2006 final rule, which 
are more stringent than the standards in effect prior to the adoption 
of the amendments, remain in effect and will continue to apply to 
affected facilities for which construction was commenced after February 
28, 2005, but before May 4, 2011. Following careful consideration of 
all of the relevant factors, EPA is proposing to establish amended 
standards for PM, SO2, and NOX which would apply 
to owners/operators of affected facilities constructed, reconstructed, 
or modified after May 3, 2011.
    In terms of the timing of our response to the remand, we consider 
it appropriate to propose revisions to the NSPS in conjunction with 
proposing the EGU NESHAP. There are some commonalities among the 
controls needed to comply with the requirements of the two rules and 
syncing the two rules so that they apply to the same set of new sources 
will allow owners/operators of those sources to better plan to comply 
with both sets of requirements. Therefore, we are proposing these 
revisions in conjunction with proposing the NESHAP, and intend to 
finalize both rules simultaneously.
    As explained in more detail below and in the technical support 
documents, we have concluded that the proposed PM, SO2, and 
NOX standards set forth in this proposed rule reflect BDT. 
In addition, we have concluded that the most appropriate approach to 
reduce emissions of both filterable PM2.5 and condensable PM 
is to establish a total PM standard, rather than establishing separate 
standards for each form of PM.The total PM standard, total filterable 
PM plus condensable PM, set forth in this proposed rule reflects BDT 
for all forms of PM. We have concluded that establishing a single total 
PM standard is preferable for a number of reasons. First, this approach 
effectively accounts for and requires control of both primary forms of 
PM, filterable PM, which includes both filterable PM10 (PM 
in the stack with an aerodynamic diameter less than or equal to a 
nominal 10 micrometers) and filterable PM2.5 (PM in the 
stack with an aerodynamic diameter less than or equal to a nominal 2.5 
micrometers) and condensable PM (materials that are vapors or gases at 
stack conditions but form solids or liquids upon release to the 
atmosphere). Second, we have concluded that the same control device 
constitutes BDT for both forms of filterable PM. Best demonstrated 
technology for control of both filterable PM10 and 
filterable PM2.5 emissions from steam generating units is 
based upon the use of a FF with coated or membrane filter media bags. 
Fabric filters control the fine particulate sizes that compose 
filterable PM2.5 and the coarser particulate sizes that are 
a component of filterable PM10 through the same means. Since 
a FF controls total filterable PM and cannot selectively control 
filterable PM2.5, establishing separate filterable 
PM2.5 and filterable PM10 standards would not 
result in any further reduction in emissions. Thus, although the NSPS 
for steam generating units do not establish individual standards for 
filterable PM10 and PM2.5, the NSPS PM standards 
for steam generating units do result in control of both of these 
filterable PM size categories based on the use of the control 
technologies identified as BDT and used to derive the proposed PM 
standards. Third, size fractionation of the PM in stacks with entrained 
water droplets (i.e., those downstream of a wet FGD scrubber) is 
challenging since the water droplets contain suspended and dissolved 
material which would form particulate after exiting the stack when the 
water droplet is evaporated. This challenge is exacerbated due to the 
difficulties of collecting the water droplets and quickly evaporating 
the water to reconstitute the suspended and dissolved materials in 
their eventual final size without changing their size as a result of 
shattering, agglomeration and deposition on the sample equipment. 
Although the Agency and others are working toward technologies that may 
allow particle sizing in wet stack conditions, there is currently no 
viable test method to determine the size fraction of the filterable PM 
for stacks that contain water droplets. Because many new EGUs are 
expected to use wet scrubbers and/or a WESP, owners/operators of these 
units would have no method to determine compliance with a fine 
filterable PM standard.
    Under the existing NSPS, BDT for an owner/operator of a new 
affected facility is a FF for control of filterable PM and an FGD for 
control of SO2. Depending on the specific stack conditions 
and coal type being burned, fabric filters may also provide some co-
benefit reduction in condensable PM emissions. Furthermore, an FGD 
designed for SO2 control has the co-benefit of reducing, to 
some extent, condensable PM emissions. Therefore, the existing NSPS 
baseline for control of condensable PM is a FF in combination with an 
FGD. We have concluded that the additional use of a WESP system in 
combination with DSI is BDT for condensable PM. We have concluded that 
it is appropriate to regulate both filterable and condensable PM under 
a single standard since they may be impacted differently by common 
controls. For example, DSI is one of the approaches that could be used 
to reduce the sulfuric acid mist (SO3 and 
H2SO4) portion of the condensable PM. However, 
addition of sorbent adds filterable PM to the system and could 
conceivably increase filterable PM emissions. When using a wet FGD, 
some small amount of scrubber solids (gypsum, limestone) can be 
entrained into the exiting gas, resulting in an

[[Page 25061]]

increase in filterable PM emissions. In each of these cases, 
technologies used to meet a stringent separate condensable PM standard 
could result in an increase in filterable PM emissions, a portion of 
which consist of fine filterable PM. This increase in filterable PM may 
challenge the ability of the owner/operator of the affected facility to 
meet a similarly stringent filterable PM standard. Filterable and 
condensable PM are often controlled using separate or complimentary 
technologies--though there are technologies, (e.g., WESP), that can 
control both filterable and condensable PM emissions. Often times the 
equipment is used to also control other pollutants such as 
SO2, HCl, and Hg. A combined PM standard allows for optimal 
design and operation of the control equipment. Thus, with the data 
available to us it is unclear what system of emissions reduction would 
result in the best overall environmental performance if we attempted to 
established separate filterable and condensable PM standards and what 
an appropriate condensable PM standard would be. At this time, the use 
of a total PM standard is the most effective indicator that the 
emissions standard is providing the best control of both filterable and 
condensable PM2.5 emissions as well as coarse filterable PM 
emissions. We are requesting comment on whether separate filterable 
PM2.5 and condensable PM standards would be appropriate and 
what the numerical values of any such standards should be.
    EPA disagrees with the petitioners claim that the NSPS should be 
based on the performance of IGCC units. The NSPS is a national standard 
and IGCC is not appropriate in every situation. Although IGCC units 
have many advantages, technology choice is based on several factors, 
including the goals and objectives of the owner or operator 
constructing a facility, the intended purpose or function of the 
facility, and the characteristic of the particular site. In addition, 
the emissions benefits resulting from reduced emissions of criteria 
pollutants are not sufficient in all instances to justify the higher 
capital costs of today's IGCC units if IGCC is selected as BDT in 
establishing a national standard. The emissions benefits may, however, 
be sufficient to justify the use of IGCC in an individual case, after 
considering cost and other relevant factors, including those described 
above.

D. EPA's Response to the Utility Air Regulatory Group's Petition for 
Reconsideration

    On January 28, 2009, EPA promulgated amendments separate from the 
above mentioned amendments to the NSPS for EGUs (40 CFR part 60, 
subpart Da, 74 FR 5,072). The Utility Air Regulatory Group (UARG) 
subsequently requested reconsideration of that rulemaking and EPA 
granted that reconsideration. Specific issues raised by UARG included 
the opacity monitoring requirements for owners/operators of affected 
facilities subject to an opacity standard that are not required to 
install a continuous opacity monitoring system (COMS). Another issue 
raised by UARG was the opacity standard for owners/operators of 
affected facilities subject to 40 CFR part 60, subpart D. We are 
requesting comments on both of these issues in this rulemaking.

VII. Summary of the Significant Proposed NSPS Amendments

    The proposed amendments would amend the emission limits for PM, 
SO2, and NOX from steam generating units in 40 
CFR part 60, subpart Da. Only those facilities that begin construction, 
modification, or reconstruction after May 3, 2011 would be affected by 
the proposed amendments. In addition to proposing to amend the 
identified emission limits, we are also proposing several less 
significant amendments, technical clarifications, and corrections to 
various provisions of the existing utility and industrial steam 
generating unit NSPS, as explained below.

A. What are the proposed amended emissions standards for EGUs?

    We are proposing to amend the PM, SO2, and 
NOX standards for owners/operators of new, modified, and 
reconstructed units on which construction is commenced after May 3, 
2011 as follows. We are proposing a total PM emissions standard 
(filterable plus condensable PM) for owners/operators of new and 
reconstructed EGUs of 7.0 nanograms per joule (ng/J) (0.055 lb/MWh) 
gross energy output. The proposed PM standard for modified units is 15 
ng/J (0.034 lb/MMBtu) heat input.
    We are proposing an SO2 emissions standard for new and 
reconstructed EGUs of 130 ng/J (1.0 lb/MWh) gross energy output or a 97 
percent reduction of potential emissions regardless of the type of fuel 
burned with the following exception. We are not proposing to amend the 
SO2 emissions standard for EGUs that burn over 75 percent 
coal refuse. We are also not proposing to amend the SO2 
emission standard for owners/operators of modified EGUs because of the 
incremental cost effectiveness and potential site specific limited 
water availability. Without access to adequate water supplies owners/
operators of existing facilities would not be able to operate a wet 
FGD.
    We are co-proposing two options for an amended NOX 
emissions standard. EPA's preferred approach would establish a combined 
NOX plus CO standard for owners/operators of new, 
reconstructed, and modified units. The proposed combined standard for 
new and reconstructed EGUs is 150 ng/J (1.2 (lb NOX + lb 
CO)/MWh) and the proposed combined standard for modified units is 230 
ng/J (1.8 (lb NOX + lb CO)/MWh). EPA prefers the approach of 
establishing a combined standard because it provides additional 
compliance flexibility while still providing an equivalent or superior 
level of environmental protection. Alternatively, we are proposing to 
amend the NOX emission standard for new, modified, and 
reconstructed EGUs to 88 ng/J (0.70 lb/MWh) gross energy output 
regardless of the type of fuel burned and not establish any CO 
standards.
    In addition to proposing revised emission standards, we are also 
proposing to amend the way an owner/operator of an affected facility 
would calculate compliance with the proposed standards. Under the 
existing NSPS, averages are calculated as the arithmetic average of the 
non out-of-control hourly emissions rates (i.e., hours during which the 
monitoring device has not failed a quality assurance or quality control 
test) during the applicable averaging period. For the revised 
standards, we are proposing that the average be calculated as the sum 
of the applicable emissions divided by the sum of the gross output of 
non out-of-control hours during the averaging period. We are proposing 
this change in part to facilitate moving from the existing PM, 
SO2, and NOX standards, which exclude periods of 
startup and shutdown, to the proposed PM, SO2, and 
NOX standards, which would include periods of startup and 
shutdown.

B. Would owners/operators of any EGUs be exempt from the proposed 
amendments?

    We are proposing several amendments that would exempt owners/
operators from certain of the proposed amendments. First, we are 
proposing that owners/operators of innovative emerging technologies 
that apply for and are granted a commercial demonstration permit by the 
Administrator for an affected facility that uses a pressurized 
fluidized bed, a multi-pollutant emissions control system, or advanced 
combustion controls be exempt from the proposed

[[Page 25062]]

amended standard. Owners/operators of these technologies would instead 
demonstrate compliance with standards similar to those finalized in the 
2006 amendments. The total PM standard would be 0.034 lb/MMBtu heat 
input, the SO2 standard would be 1.4 lb/MWh gross output or 
a 95 percent reduction in potential emissions, and the NOX 
standard would be 1.0 lb/MWh gross output. In the event we finalize a 
combined NOX/CO standard, the corresponding combined limit 
would be 1.4 lb/MWh gross output. In addition, we are proposing to 
harmonize all of the steam generating unit NSPS by exempting all steam 
generating units combusting natural gas and/or low sulfur oil from PM 
standards and exempting all steam generating units burning natural gas 
from opacity standards. Finally, we are proposing to exempt owners/
operators of affected facilities subject to 40 CFR part 60, subpart Eb 
(standards of performance for large MWCs), from 40 CFR part 60, subpart 
Da, exempt owners/operators of affected facilities subject to 40 CFR 
part 60, subpart CCCC (standards of performance for commercial and 
industrial solid waste incineration), units from 40 CFR part 60, 
subparts Da, Db, and Dc, exempt owners/operators of affected facilities 
subject to 40 CFR part 60, subpart BB (standards of performance for 
Kraft pulp mills), from the PM standards under 40 CFR part 60, subpart 
Db, and exempt owners/operators of fuel gas combustion devices subject 
to 40 CFR part 60, subpart Ja (standards of performance for petroleum 
refineries), from the SO2 standard under 40 CFR part 60, 
subpart Db.

C. What other significant amendments are being proposed?

    A complete list of the corrections and technical amendments and 
corrections is available in the docket in the form of a redline/
strikeout version of the existing regulatory language. These additional 
amendments are being proposed to clarify the intent of the current 
requirements, correct inaccuracies, and correct oversights in previous 
versions that were promulgated. The additional significant amendments 
are as follows.
    We are proposing several definitional changes. First, to provide 
additional flexibility and recognize the environmental benefit of 
efficient production of electricity we are proposing to expand the 
definition of the affected facility under 40 CFR part 60, subpart Da, 
to include integrated CTs and fuel cells. Second, because petroleum 
coke is increasingly being burned in EGUs selling over 25 MW of 
electric output, we are proposing to amend the definition of petroleum 
to include petroleum coke. Next, to minimize permitting and compliance 
burdens and avoid situations where an IGCC facility switches between 
different NSPS (40 CFR part 60, subparts KKKK and Da), we are proposing 
to amend the definition of an IGCC facility to allow the Administrator 
to exempt owners/operators from the 50 percent solid-derived fuel 
requirement during construction and repair of the gasifier. Owners/
operators of IGCC units might install and operate the stationary CT 
prior to completion of the gasification system. Under the existing 
standards, an owner/operator doing this would first be subject to 40 
CFR part 60, subpart KKKK, and applicability would switch once the 
gasification system is completed. This outcome would not result in any 
additional reduction in emissions. The proposed change would thus 
reduce regulatory burden without decreasing environmental protection. 
Finally, both biodiesel and kerosene have combustion characteristics 
similar to those of distillate oil. Therefore, we are proposing to 
expand the definition of distillate oil in 40 CFR part 60, subparts Db 
and Dc, to include both biodiesel and kerosene such that units burning 
any of these fuels, either separately or in combination would be 
subject to the same requirements.
    Additional proposed amendments include deleting vacated provisions 
and additional harmonization across the various steam generating unit 
NSPS. As explained above, CAMR was vacated by the DC Circuit Court in 
2008. As a result, the provisions added to 40 CFR part 60, subpart Da, 
by CAMR are no longer enforceable. Therefore, we are proposing to 
delete the provisions in 40 CFR part 60, subpart Da, that reference Hg 
standards and Hg testing and monitoring provisions. In addition, 
existing 40 CFR part 60, subpart HHHH (Emission Guidelines and 
Compliance Times for Coal-Fired Electric Steam Generating Units), which 
was promulgated as part of CAMR, and was, therefore, also vacated by 
the court's decision, will be removed and that subpart will be deleted. 
We are proposing to harmonize all of the steam generating unit NSPS by 
adding BLDS and ESP parameter monitoring systems as alternatives to the 
requirement to install a COMS in all the subparts (40 CFR part 60, 
subparts D, Da, Db, and Dc). We are also proposing to change the date 
by which owners/operators of affected facilities subject to all of the 
steam generating unit NSPS are to begin submitting performance test 
data electronically from July 1, 2011, to January 1, 2012.

VIII. Rationale for This Proposed NSPS

    The proposed new emission standards for EGUs would apply only to 
affected sources that begin construction, modification, or 
reconstruction after May 3, 2011. Based on our review of emission data 
and control technology information applicable to criteria pollutants, 
we have concluded that amendments of the PM, SO2, and 
NOX emission standards are appropriate. The technical 
support documents that accompany the proposal describe in further 
detail how the proposed amendments to the NSPS reflect the application 
of the BDT for these sources considering the performance and cost of 
the emission control technologies and other environmental, health, and 
energy factors. In establishing the proposed revised emission limits 
based on BDT, we have to the extent that it is practical and reasonable 
to do so adopted a fuel and technology neutral approach and have 
expressed the proposed emission limits on an output basis. These 
approaches provide the level of emission limitation required by the CAA 
for the NSPS program while at the same time achieving the additional 
benefits of compliance flexibility, increased efficiency, and the use 
of cleaner fuels.
    The fuel and technology neutral approach provides a single emission 
limit for steam generating units based on the application of BDT 
without regard to the specific type of steam generating equipment or 
fuel being used. We have concluded that this approach provides owners/
operators of affected facilities an incentive to carefully consider 
fuel use, boiler type, and control technology in planning for new units 
so as to use the most effective combination of add-on control 
technologies, clean fuels, and boiler design based on the circumstances 
to meet the emission standards.
    To develop a fuel- and technology-neutral emission limit, we first 
analyzed data on emission control performance from coal-fired units to 
establish an emission level that represents BDT for units burning coal. 
We adopted this approach because the higher sulfur, nitrogen, and ash 
contents for coal compared to oil or gas makes application of BDT to 
coal-fired units more complex than application of BDT to either oil- or 
gas-fired units. Because of these complexities, emission levels 
selected for coal-fired steam generating units using BDT would also be 
achievable by oil- and gas-fired EGUs. Thus, we are proposing that the

[[Page 25063]]

emission levels established through the application of BDT to coal-
fired units apply to all boiler types and fuel use combinations. We 
have concluded that this fuel-neutral approach both satisfies the 
requirements of CAA section 111(b) and provides a clear incentive to 
use cleaner fuels where it is possible to do so.
    Where feasible, we are proposing output-based (gross basis) 
standards in furtherance of pollution prevention which has long been 
one of our highest priorities. In the current context, maximizing the 
efficiency of energy generation represents a key opportunity to further 
pollution prevention. An output-based format establishes emission 
standards that encourage unit efficiency by relating emissions to the 
amount of useful-energy generated, not the amount of fuel burned. By 
relating emission limitations to the productive output of the process, 
output-based emission standards encourage energy efficiency because any 
increase in overall energy efficiency results in a lower emissions 
rate. Output-based standards provide owners/operators of regulated 
sources with an additional compliance option (i.e., increased 
efficiency in producing useful output) that can result in both reduced 
compliance costs and lower emissions. The use of more efficient 
generating technologies reduces fossil fuel use and leads to multi-
media reductions in environmental impacts both on-site and off-site. 
On-site benefits include lower emissions of all products of combustion, 
including HAP, as well as reducing any solid waste and wastewater 
discharges. Off-site benefits include the reduction of emissions and 
non-air environmental impacts arising from the production, processing, 
and transportation of fuels and the disposal of by-products of 
combustion such as fly-ash and bottom-ash.
    The general provisions in 40 CFR part 60 provide that ``emissions 
in excess of the level of the applicable emissions limit during periods 
of startup, shutdown, and malfunction (shall not be) considered a 
violation of the applicable emission limit unless otherwise specified 
in the applicable standard.'' 40 CFR 60.8(c). EPA is proposing 
standards in this rule that apply at all times, including during 
periods of startup or shutdown, and periods of malfunction. In 
proposing the standards in this rule, EPA has taken into account 
startup and shutdown periods and, for the reasons explained below, has 
not proposed different standards for those periods.
    To establish the proposed output-based SO2 and 
NOX standards, we used hourly pollutant emissions data and 
gross output data as reported to the Clean Air Markets Division (CAMD) 
of EPA. In general, retrofit existing units can perform as well as 
recently operational units. To establish a robust data set on which to 
base the proposed amendments, we analyzed emissions data from both 
older plants that have been retrofitted with controls and recently 
operational units. We did not attempt to filter out periods of startup 
or shutdown and the proposed standards, therefore, account for those 
periods.
    If any persons believe that our conclusion is incorrect, or that we 
have failed to consider any relevant information on this point, we 
encourage them to submit comments. In particular, we note that the 
general provisions in 40 CFR part 60 require facilities to keep records 
of the occurrence and duration of any startup, shutdown or malfunction 
(40 CFR 60.7(b)) and either report to EPA any period of excess 
emissions that occurs during periods of startup, shutdown, or 
malfunction (40 CFR 60.7(c)(2)) or report that no excess emissions 
occurred (40 CFR 60.7(c)(4)). Thus, any comments that contend that 
sources cannot meet the proposed standard during startup and shutdown 
periods should provide data and other specifics supporting their claim.
    In developing the proposed 30-day SO2 and NOX 
standards, we summed the unadjusted emissions for all non-out-of-
control operating hours and divided that value by the sum of the gross 
electrical energy output over the same period. For the purposes of this 
analysis, out-of-control hours were defined as when either the 
unadjusted applicable emissions or gross output could not be determined 
for that operating hour. The reduction in potential SO2 
emissions was calculated by comparing the reported SO2 
emissions during a 30-day period to the potential emissions for that 
same 30-day period. Potential uncontrolled SO2 emissions 
were calculated using monthly delivered fuel receipts and fuel quality 
data from the EIA forms EIA-923, EIA-423, and FERC-423, as applicable. 
For each operating day, the total potential uncontrolled SO2 
emissions were calculated by multiplying the uncontrolled 
SO2 emissions rate for the applicable month as determined 
using the EIA data by the heat input for that day. This revised 
averaging approach gives more weight to high load hours and more 
accurately reflects overall environmental performance. In addition, 
because low load hours do not factor as heavily into the calculated 
average the impact of including periods of startup and shutdown is 
minimized.
    Particulate matter and CO data are not reported to CAMD and instead 
were collected as part of the 2010 ICR. Total PM testing was reported 
as part of the 2010 ICR and those data were used in both rulemakings. 
As part of the 2010 ICR, owners/operators reported CO performance test 
data and whether or not they have a CO CEMS installed on their 
facility. We requested CO CEMS data from multiple units to compare the 
relationship between NOX and CO. The 30-day combined 
NOX/CO standard was calculated using the same approach as 
for NOX and SO2.

A. How are periods of malfunction addressed?

    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 60.2.) EPA has determined that 
malfunctions should not be viewed as a distinct operating mode and, 
therefore, any emissions that occur at such times do not need to be 
factored into development of CAA section 111 standards. Further, 
nothing in CAA section 111 or in case law requires that EPA anticipate 
and account for the innumerable types of potential malfunction events 
in setting emission standards. See, Weyerhaeuser v Costle, 590 F.2d 
1011, 1058 (DC 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.'')
    Further, it is reasonable to interpret CAA section 111 as not 
requiring EPA to account for malfunctions in setting emissions 
standards. For example, we note that section 111 provides that EPA set 
standards of performance which reflect the degree of emission 
limitation achievable through ``the application of the best system of 
emission reduction'' that EPA determines is adequately demonstrated. 
Applying the concept of ``the application of the best system of 
emission reduction'' to periods during which a source is malfunctioning

[[Page 25064]]

presents difficulties. The ``application of the best system of emission 
reduction'' is more appropriately understood to include operating units 
in such a way as to avoid malfunctions.
    Moreover, even if malfunctions were considered a distinct operating 
mode, we believe it would be impracticable to take malfunctions into 
account in setting CAA section 111 standards for EGUs under 40 CFR part 
60, subpart Da. As noted above, by definition, malfunctions are sudden 
and unexpected events and it would be difficult to set a standard that 
takes into account the myriad different types of malfunctions that can 
occur across all sources in the category. Moreover, malfunctions can 
vary in frequency, degree, and duration, further complicating standard 
setting.
    In the event that a source fails to comply with the applicable CAA 
section 111 standards as a result of a malfunction event, 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 to ascertain and rectify excess emissions. 
EPA would also consider whether the source's failure to comply with the 
CAA section 111 standard was, in fact, ``sudden, infrequent, not 
reasonably preventable'' and was not instead ``caused in part by poor 
maintenance or careless operation.'' 40 CFR 60.2 (definition of 
malfunction).
    Finally, EPA recognizes that even equipment that is properly 
designed and maintained can sometimes fail. 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 (September 20, 1999); Policy on 
Excess Emissions During Startup, Shutdown, Maintenance, and 
Malfunctions (February 15, 1983)). EPA is, therefore, proposing to add 
an affirmative defense to civil penalties for exceedances of emission 
limits that are caused by malfunctions. See 40 CFR 60.41Da (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 are proposing 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 40 CFR 
60.46Da. (See 40 CFR 22.24). These 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 
60.2 (sudden, infrequent, not reasonably preventable and not caused by 
poor maintenance and or careless operation). For example, to 
successfully assert the affirmative defense, 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 40 CFR 60.40Da and to prevent future 
malfunctions. For example, the source would have to 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 the 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 part 22.77).

B. How did EPA determine the proposed emission limitations?

1. Selection of the Proposed PM Standard
    Controls for filterable PM are well established. Either an ESP or 
FF can control both coarse and fine filterable PM. However, controls 
for condensable PM are less developed. Condensable PM from a coal-fired 
boiler is composed primarily of SO3 and 
H2SO4 but may also contain smaller amounts of 
nitrates, halides, ammonium salts, and volatile metals such as 
compounds of Hg and Se. Controls that are expected to reduce emissions 
of condensable PM include the use of lower sulfur coals, the use of an 
SCR catalyst or other NOX control device with minimal 
SO2 to SO3 conversion, use of an FGD scrubber, 
injection of an alkaline sorbent upstream of a PM control device, and 
use of a WESP. Other control technologies such as FFs or ESPs may also 
provide some reduction in condensable PM--depending on the flue gas 
temperature and the composition of the fly ash and other bulk PM. It is 
unlikely that owners/operators of modified units could universally 
further reduce the condensable fraction of the PM as they already have 
FGD controls, operating the PM control at a cooler temperature (or 
relocating to a cooler location) are not practical options due to 
concerns with corrosion, and it is possible that the existing ductwork 
might not make DSI viable without significant adjustments. Therefore, 
we have concluded that BDT for modified units should be based on the 
use of a FF in combination with an FGD. Based on the 2010 ICR data for 
total PM, there are performance tests for 63 units below the existing 
NSPS filterable PM standard (0.015 lb/MMBtu), that have some type of 
SO2 control, and that use a FF. Ninety four percent of these 
performance tests are achieving an emissions rate of 0.034 lb/MMBtu for 
total PM, and we have concluded that this value is an achievable 
standard for owners/operators of modified units. It is also 
approximately equivalent in stringency to the existing filterable PM 
standard because no specific condensable PM controls would necessarily 
be required. However, we have concluded that new EGUs will factor in 
condensable PM controls. BDT for new EGUs would be a FF and FGD in 
combination with both DSI and a WESP. Based on the 2010 ICR data for 
total PM, there are performance tests for 48 units below the existing 
NSPS filterable PM standard (0.015 lb/MMBtu), that have some type of 
SO2 control, that use a FF, and that reported gross 
electrical output during the performance test. Because no owners/
operators of EGUs are presently specifically attempting to control 
condensable PM beyond eliminating the visible blue plume that can occur 
from sulfuric acid mist emissions, we concluded it was appropriate to 
use the top 20 percentile of the performance test data for the proposed 
total PM standard. The top 20 percentile of these performance tests is 
7.0 ng/J (0.055 lb/MWh). We are soliciting comments on the proposed 
standard and are considering the range of 15 ng/J (0.034 lb/MMBtu) to 
5.0 ng/J (0.040 lb/MWh) for the final rule. We are also requesting 
comment on whether an input-based standard is more appropriate for 
standards where compliance is based on performance tests instead of 
CEMS.

[[Page 25065]]

2. How did EPA select the proposed SO2 standard?
    A number of SO2 control technologies are currently 
available for use with new coal-fired EGUs. Owners/operators of new 
steam generating projects that use IGCC technology can remove the 
sulfur associated with the coal in downstream processes after the coal 
has been gasified. Owner/operators of new steam generating units that 
use FBC technology can control SO2 during the combustion 
process by adding limestone into the fluidized-bed, and, if necessary, 
installing additional post-combustion controls. Owners/operators of 
steam generating units using PC combustion technology can use post-
combustion controls to remove SO2 from the flue gases. 
Additional control strategies that apply to all steam generating units 
include the use of low sulfur coals, coal preparation to improve the 
coal quality and lower the sulfur content, and fuel blending with 
inherently low sulfur fuels.
    To assess the SO2 control performance level of EGUs, we 
reviewed new and retrofitted units with SO2 controls. Table 
17 of this preamble shows the performance of several of the best 
performing units in terms of percent reduction in potential 
SO2 emissions identified in our analysis of coal-fired EGUs.

                                    Table 17--SO2 Emissions Performance Data
----------------------------------------------------------------------------------------------------------------
                                                                               Maximum  30-day   Minimum  30-day
                        Facility                              Time period       SO2 emissions      percent SO2
                                                                               rate  (lb/MWh)       reduction
----------------------------------------------------------------------------------------------------------------
Cayuga 1................................................         12/08-12/09              1.03              97.4
Harrison 1..............................................         01/06-01/09              1.45              96.7
Harrison 2..............................................         01/06-01/09              1.01              97.7
Harrison 3..............................................         01/06-01/09              0.97              98.2
HL Spurlock 1...........................................         06/09-12/09              1.83              96.9
HL Spurlock 2...........................................         11/08-12/09              1.26              98.0
HL Spurlock 3...........................................         01/09-12/09              1.45              96.5
HL Spurlock 4...........................................         01/09-12/09              1.08              97.7
Wansley 1...............................................         02/09-12/09              0.31              97.7
Wansley 2...............................................         05/09-12/09              0.37              97.4
Iatan 1.................................................         04/09-12/09              0.16              98.2
Jeffrey 2...............................................         05/09-12/09              0.09              99.0
Jeffrey 3...............................................         04/09-12/09              0.13              98.5
Trimble County 1........................................         01/05-12/09              1.14              97.6
Mountaineer 1...........................................         05/07-12/09              1.15              97.6
----------------------------------------------------------------------------------------------------------------

    With the exception of the HL Spurlock 3 and 4 units all of the 
listed units use wet limestone-based scrubbers. HL Spurlock 3 and 4 are 
FBC boilers that remove the majority of SO2 using limestone 
injection into the boiler and then remove additional SO2 by 
lime injection into the ductwork prior to the FF. Of the identified 
best performing units, we only have multiple years of performance data 
for the Harrison, Trimble County, and Mountaineer units. Based on the 
performance of these units, we have concluded that 97 percent reduction 
in potential SO2 emissions has been demonstrated and is 
achievable on a long term basis. This level of reduction has also been 
demonstrated at each separate unit at each location in Table 17 of this 
preamble and accounts for variability in performance of individual 
scrubbers. Therefore, the proposed upper limit on a percent reduction 
basis is 97 percent. Even though the Iatan and Jeffrey units are 
achieving a 98 percent reduction in potential SO2 emissions, 
we are not proposing this standard because it is based on relatively 
short-term data. Based on the variability in SO2 reductions 
from the Harrison, Trimble County, and Mountaineer units, we have 
concluded that short-term data do not necessarily take into account the 
range of operating conditions that a facility would be expected to 
operate or control equipment variability and degradation. We are 
soliciting comments on the proposed limit and are considering the range 
of 96 to 98 percent reduction in potential SO2 emissions for 
the final rule.
    To determine an appropriate alternate numerical standard, we 
evaluated the performance of several recently constructed units in 
addition to the numerical standards for the units in Table 17 of this 
preamble. Table 18 of this preamble shows the maximum 30-day average 
SO2 emissions rate of units that commenced operation between 
2005 and 2008, that are emitting at levels below the current NSPS, and 
that reported both SO2 emissions and gross electric output 
data to CAMD.

                              Table 18--SO2 Emissions Performance Data for New EGUs
----------------------------------------------------------------------------------------------------------------
                                                                                                   Maximum  30-
                                                                                    In service        day SO2
                  Facility                          SO2 control technology             date       emissions rate
                                                                                                      (lb/MWh)
----------------------------------------------------------------------------------------------------------------
Weston 4...................................  Lime-based Spray Dryer.............            2008            0.61
Cross 4....................................  Wet Limestone FGD..................            2008            1.02
TS Power Plant 1...........................  Lime-based Spray Dryer.............            2008            0.56
Wygen II...................................  Lime-based Spray Dryer.............            2008            0.95
Walter Scott Jr. Energy Center 4...........  Lime-based Spray Dryer.............            2007            0.73
Cross 3....................................  Wet Limestone FGD..................            2007            1.06
Springerville TS3..........................  Lime-based Spray Dryer.............            2006            1.04
HL Spurlock 3..............................  Fluidized Bed Limestone Injection +            2005            1.45
                                              Lime Injection.
----------------------------------------------------------------------------------------------------------------


[[Page 25066]]

    The HL Spurlock 3 unit is the only new unit that burns high sulfur 
coal and that unit could meet the proposed alternate percent reduction 
standard. However, it would not be expected to achieve a numerical 
standard based on the performance of the other units. Further, with the 
exception of the Cross 3 and 4 units, which burn medium sulfur 
bituminous coals, the remaining units burn lower-sulfur subbituminous 
coals. To provide the maximum emissions reduction, we further concluded 
that the alternate numerical standard should be as stringent as the 
numerical rates achieved by the units used to determine the percent 
reduction standard. If the alternate numerical standard were less 
stringent than the emissions rate achieved by the units used to 
determine the maximum percent reduction, those units would not be 
required to achieve the maximum percent reduction that has been 
demonstrated. In addition, the numerical standard should account for 
variability in today's SO2 control technologies and provide 
sufficient compliance margin for owners/operators of new units burning 
medium sulfur coals to comply with the numerical standard and thereby 
provide an incentive to burn cleaner fuels. The sulfur concentrations 
in the flue gas of EGUs burning medium and low sulfur coals is more 
diffuse than for EGUs burning high sulfur coals, and it has not been 
demonstrated that units burning these coals would be able to achieve 97 
percent reduction of potential emissions on a continuous basis. We are 
proposing 1.0 lb/MWh as the alternate numerical standard because it 
provides a comparable level of performance to the 97 percent reduction 
requirement and satisfies criteria mentioned above. The numerical 
standard would require at least 80 percent reduction even from the 
lowest sulfur coals and would accommodate the use of traditional spray 
dryer scrubbers for owner/operators of new units burning coal with 
uncontrolled SO2 emissions of up to approximately 1.6 lb/
MMBtu.
    Based on the performance of the spray dryer at the Springerville 
TS3 unit, the numerical standard would provide sufficient flexibility 
such that an owner/operator of an EGU could burn over 90 percent of the 
subbituminous coals presently being used in combination with a spray 
dryer. This technology choice provides owners/operators the flexibility 
to minimize water use and associated waste water discharge, as well as 
reducing additional CO2 that is chemically created as part 
of the SO2 control device. Even though there is not 
necessarily an overall greenhouse (GHG) reduction from using a lime-
based instead of a limestone-based scrubber, lime production facilities 
have relatively concentrated CO2 streams. Capture and 
storage of CO2 at the lime manufacturing facility could 
potentially be easier since separation of the CO2 would not 
be necessary, as is the case with an EGU exhaust gas. Owners/operators 
of new and reconstructed units burning coals with higher uncontrolled 
SO2 emissions would either have to use IGCC with a 
downstream process to control sulfur prior to combustion, FBC, or a wet 
SO2 scrubbing system to comply with the proposed standard. 
The proposed limit would allow the higher sulfur coals (uncontrolled 
emissions of greater than approximately 3 lb SO2/MMBtu) to 
demonstrate compliance with the 97 percent reduction requirement as an 
alternate to the numerical limit. We are soliciting comments on the 
proposed limit and are considering the range of 100 to 150 ng/J (0.80 
to 1.2 lb/MWh) for the final rule.
    Coal refuse (also called waste coal) is a combustible material 
containing a significant amount of coal that is reclaimed from refuse 
piles remaining at the sites of past or abandoned coal mining 
operations. Coal refuse piles are an environmental concern because of 
acid seepage and leachate production, spontaneous combustion, and low 
soil fertility. Units that burn coal refuse provide multimedia 
environmental benefits by combining the production of energy with the 
removal of coal refuse piles and by reclaiming land for productive use. 
Consequently, because of the unique environmental benefits that coal 
refuse-fired EGUs provide, these units warrant special consideration so 
as to prevent the amended NSPS from discouraging the construction of 
future coal refuse-fired EGUs in the U.S.
    Coal refuse from some piles has sulfur contents at such high levels 
that they present potential economic and technical difficulties in 
achieving the same SO2 standard that we are proposing for 
higher quality coals. Therefore, so as not to preclude the development 
of these projects, we are proposing to maintain the existing 
SO2 emissions standard for owners/operators of affected 
facilities combusting 75 percent or more coal refuse on an annual 
basis.
    We are proposing to maintain the existing SO2 standard 
for modified units to preserve the use of spray dryer FGD. Existing 
units might not have access to adequate water for wet FGD scrubbers and 
it is not generally cost effective to upgrade existing spray dryer FGD 
scrubbers to a wet FGD scrubber. In addition, the 90 percent sulfur 
reduction for modified units also allows existing modified FBCs to 
comply without the addition of post-combustion SO2 controls. 
We have concluded that it is not generally cost effective to add 
additional post combustion SO2 controls for modified 
fluidized beds.
3. Selection of the Proposed NOX Standard
    In the 2006 final NSPS amendments (71 FR 9866), EPA concluded that 
advanced combustion controls were BDT. However, upon further review we 
have concluded this was not appropriate. Although select existing PC 
EGUs burning subbituminous coals have been able to achieve annual 
NOX emissions of less than 1.0 lb/MWh (e.g., Rush Island, 
Newton), PC EGUs burning other coal types using only combustion 
controls have not demonstrated similar emission rates. Lignite-fired PC 
EGUs have only demonstrated an annual NOX emissions rate of 
1.7 lb/MWh (e.g., Martin Lake) and the best bituminous fired PC EGUs 
using only combustion controls are slightly higher than 2.0 lb/MWh on 
an annual basis (e.g., Jack McDonough, Brayton Point, AES Cayuga, 
Genoa). The variability in NOX control technologies results 
in a maximum 30-day average emissions rate typically being \1/4\ to \1/
3\ higher than the annual average emissions rate. Therefore, it has not 
been demonstrated that owners/operators of PC EGUs burning any coal 
type using advanced combustion controls could comply with the existing 
NOX standard.
    After re-evaluating the performance, costs, and other environmental 
impacts of adding SCR in addition to combustion controls, we have 
concluded that combustion controls in combination with SCR represents 
BDT for continuous reduction of NOX emissions from EGUs. 
Therefore, the regulatory baseline for NOX emissions is 
defined to be combustion controls in combination with the installation 
of SCR controls on all new PC-fired units.
    To assess the NOX control performance level of EGUs, we 
reviewed new and retrofitted units with post combustion NOX 
controls. Table 19 of this preamble shows the performance of several of 
the best performing units identified in our analysis of coal-fired 
EGUs.

[[Page 25067]]



                                         Table 19--NOX Performance Data
----------------------------------------------------------------------------------------------------------------
                                                           Maximum 30-day
              Facility                    Time period      NOX  emissions      Boiler type & primary coal rank
                                                           rate  (lb/MWh)
----------------------------------------------------------------------------------------------------------------
Havana 9............................         01/05-12/09              0.70  PC, Sub.
Walter Scott Jr. 4..................         04/07-12/09              0.58  PC, Sub.
Mirant Morgantown 1.................         06/07-12/09              0.65  PC, Bit.
Mirant Morgantown 2.................         06/08-12/09              0.70  PC, Bit.
Roxboro 2...........................         01/09-12/09              0.67  PC, Bit.
Cardinal 1..........................         01/09-12/09              0.38  PC, Bit.
Cardinal 2..........................         01/09-12/09              0.46  PC, Bit.
Cardinal 3..........................         01/09-12/09              0.45  PC, Bit.
Muskingum River 5...................         01/08-12/09              0.60  PC, Bit.
John E Amos.........................         06/09-12/09              0.62  PC, Bit.
Mitchell 1..........................         01/09-12/09              0.59  PC, Bit.
Mitchell 2..........................         01/09-12/09              0.54  PC, Bit.
Weston 4............................         07/08-12/09              0.48  PC, Sub.
H L Spurlock 4......................         05/09-12/09              0.67  CFB, Bit.
Wansley 1...........................         02/09-12/09              0.67  PC, Bit.
Wansley 2...........................         01/09-12/09              0.59  PC, Bit.
Nebraska City 2.....................         05/09-12/09              0.60  PC, Sub.
TS Power 1..........................         07/08-12/09              0.49  PC, Sub.
----------------------------------------------------------------------------------------------------------------
Note: PC = pulverized coal.
CFB = circulating fluidized bed.
Sub = subbituminous coal.
Bit = bituminous coal.

    All of the units listed in Table 19 of this preamble have 
demonstrated 0.70 lb/MWh is achievable. Even though some units are 
achieving a lower emissions rate, the majority of units listed in Table 
19 of this preamble have less than a year of operating data. Proposing 
a more stringent standard might not provide sufficient compliance 
margin to account for expected variability in the long term performance 
of NOX controls. Although not all affected facilities using 
SCR are currently achieving an emissions rate of 0.70 lb/MWh, all major 
boiler designs have demonstrated combustion controls that are able to 
reduce NOX emissions to levels where the addition of SCR (or 
design modifications and operating changes to existing SCR) would allow 
compliance with a NOX emissions rate of 0.70 lb/MWh. We are 
therefore selecting 88 ng/J (0.70 lb/MWh) as the proposed 
NOX standard for new, modified, and reconstructed units. The 
range of values we are currently considering for the final rule is 76 
to 110 ng/J (0.60 to 0.90 lb/MWh).
    Combustion optimization for overall environmental performance is a 
balance between boiler efficiency, NOX emissions, and CO 
emissions. Although a well operated boiler using combustion controls 
can achieve a high efficiency and both low NOX and CO 
emissions, the pollutant emissions rates are related. For example, 
NOX reduction techniques that rely on delayed combustion and 
lower combustion temperatures tend to increase incomplete combustion 
and result in a corresponding increase in CO emissions. Conversely, 
high levels of excess air can be used to control CO emissions. However, 
high levels of excess air increase NOX emissions.
    The proposed BDT for NOX is combustion controls plus the 
application of SCR. However, there are several approaches an owner/
operator could use to comply with an individual NOX 
standard. One approach would be to use combustion controls to minimize 
the formation of NOX to the maximum extent possible and then 
use a less efficient SCR systems. This tends to result in high CO 
emissions and significant unburned carbon in the fly ash. From an 
environmental perspective, we would prefer that owners/operators select 
combustion controls that result in slightly higher NOX 
emissions without substantially increasing CO emissions, and use 
regular efficiency SCR systems. As compared to establishing individual 
pollutant emission standards, a combined NOX plus CO 
standard accounts for variability in combustion properties and provides 
additional compliance strategy options for the regulated community, 
while still providing an equivalent level of environmental protection. 
In addition, a combined standard provides additional flexibility for 
owners/operators to minimize carbon and/or ammonia in the fly ash such 
that the fly ash could still be used in beneficial reuse projects.
    In addition, an overly stringent NOX standard has the 
potential to impede the ability of an owner/operator of an EGU from 
operating at peak efficiency thereby minimizing GHG emissions. A 
combined standard on the other hand allows owners/operators additional 
flexibility to operate at or near peak efficiency. A combined standard 
would also allow the regulated community to work with the local 
environmental permitting agency to minimize the pollutant of most 
concern for that specific area. We have previously established a 
combined NOX plus CO combined emissions standard for thermal 
dryers at coal preparation plants (40 CFR part 60, subpart Y).
    To assess the combined NOX/CO performance level of EGUs, 
we requested data from units identified by the 2010 ICR as using 
certified CO CEMS and achieving the existing NSPS NOX 
standard of 1.0 lb/MWh gross output. We continue to be interested in 
additional NOX and CO certified CEMS data from EGUs and 
comparable units using that are achieving the existing NSPS 
NOX standard of 1.0 lb/MWh gross output. Table 20 of this 
preamble shows the performance of the units identified in our analysis.

[[Page 25068]]



                                        Table 20--NOX/CO Performance Data
----------------------------------------------------------------------------------------------------------------
                                                             Maximum 30-
                                                              day NOX +   Maximum 30-
                                                                  CO       day NOX/CO    Boiler type & primary
                Facility                     Time period      emissions    emissions           coal rank
                                                              rate  (lb/   rate  (lb/
                                                                 MWh)         MWh)
----------------------------------------------------------------------------------------------------------------
Northside 1............................         01/05-12/09          1.1    0.89/0.29  CFB, PC.
Northside 2............................         01/05-12/09          1.1    0.93/0.46  CFB, PC.
Walter Scott, Jr. 4....................         04/07-12/09         0.95    0.58/0.42  PC, Sub.
WA Parish 5............................         09/05-12/09          1.1    0.66/0.62  PC, Sub.
WA Parish 6............................         06/05-12/09          1.2    0.76/0.81  PC, Sub.
WA Parish 7............................         06/05-12/09          1.8     0.53/1.4  PC, Sub.
WA Parish 8............................         04/06-12/09          1.5     0.42/1.1  PC, Sub.
HL Spurlock 3..........................         01/09-12/09          1.4    0.83/0.61  CFB, Bit.
HL Spurlock 4..........................         05/09-12/09          1.4    0.67/0.70  CFB, Bit.
TS Power 1.............................         04/08-12/09         0.80    0.49/0.47  PC, Sub.
----------------------------------------------------------------------------------------------------------------
Note: PC = pulverized coal or petroleum coke.
CFB = circulating fluidized bed.
Sub = subbituminous coal.

    Because CO has not historically been a primary pollutant of concern 
for owners/operators of EGUs, it has not necessarily been a significant 
factor when selecting combustion control strategies and has not 
typically been continuously monitored. Due to the limited availability 
of CO CEMS data and to account for potential variability we are not 
aware of, we have concluded it is appropriate in this case to propose a 
standard with sufficient compliance margin to not inhibit the ability 
of owner/operators of EGUs to comply with NOX specific best 
available control technology (BACT) requirements or requirements that 
result from compliance with EPA's proposed Transport Rule. Although 2 
of the units shown in Table 21 of this preamble are operating below 1.0 
lb/MWh, there are 4 that are operating in the 1.1 to 1.2 lb/MWh range. 
To provide a compliance margin and to account for situations where 
NOX might be more of a priority pollutant than CO, we are 
proposing a combined standard of 1.2 lb/MWh. This margin is apparent 
when comparing the HL Spurlock and Northside units. These fluidized bed 
boilers use selective non-catalytic reduction (SNCR) to reduce 
NOX emissions. Although the HL Spurlock units perform better 
in terms of NOX, the combustion controls result in higher CO 
and combined NOX/CO emission rates. In determining the 
appropriate combined standard for owner/operators of modified units, we 
used the data from the WA Parish units. All four of these units have 
been retrofitted to comply with stringent NOX requirements. 
Owners/operators of modified units could potentially have a more 
difficult time controlling both NOX and CO because the 
configuration of the boiler cannot be changed. All 4 of the WA Parish 
units have demonstrated that a standard of 230 ng/J (1.8 lb/MWh) is 
achievable and we are, therefore, proposing that standard for modified 
units. We are requesting comment on these standards and are considering 
a range of 130 to 180 ng/J (1.0 to 1.4 lb/MWh) for new and 
reconstructed units and of 180 to 230 ng/J (1.4 to 1.8 lb/MWh) for 
modified units.
    Another potential GHG benefit, beyond boiler efficiency, of a 
combined NOX + CO standard is the flexibility to minimize 
nitrous oxide (N2O) emissions. Formation of N2O 
during the combustion process results from a complex series of 
reactions and is dependent upon many factors. Operating factors 
impacting N2O formation include combustion temperature, 
excess air, and sorbent feed rate. The N2O formation 
resulting from SNCR depends upon the reagent used, the amount of 
reagent injected, and the injection temperature. Adjusting any of these 
factors can impact CO and/or NOX emissions, and a combined 
standard provides an owner/operator the maximum flexibility to reduce 
overall criteria and GHG emissions. Pulverized coal boilers tend to 
operate at sufficiently high temperatures so as to not generally have 
significant N2O emissions. On the other hand, fluidized bed 
boilers operate at lower temperatures and can have measurable 
N2O emissions. However, the fuel flexibility benefit (i.e., 
the ability to burn coal refuse and biomass) of fluidized bed boilers 
can help to offset the increase in N2O emissions.
4. Commercial Demonstration Permit
    The commercial demonstration permit section of the EGU NSPS was 
included in the original rulemaking in 1979 (44 FR 33580) to assure 
that the NSPS did not discourage the development of new and promising 
technologies. In the 1979 rule, the Administrator recognized that the 
innovative technology waiver provisions under CAA section 111(j) are 
not adequate to encourage certain capital intensive technologies. (44 
FR 33580.) Under the innovative technology provisions, the 
Administrator may grant waivers for a period of up to 7 years from the 
date of issuance of a waiver or up to 4 years from the start of 
operation of a facility, whichever is less. The Administrator 
recognized that this time frame is not sufficient for amortization of 
high-capital-cost technologies. The commercial demonstration permit 
section established less stringent requirements for initial full-scale 
demonstration plants that received a permit in order to mitigate the 
potential impact of the rule on emerging technologies and insure that 
standards did not preclude the development of such technologies.
    The authority to issue these permits was predicated on the DC 
Circuit Court's opinion in Essex Chemical Corp. v. Ruckelshaus, 486 F. 
2d 42 (DC Cir. 1973); NSPS should be set to avoid unreasonable costs or 
other impacts. Standards requiring a high level of performance, such as 
the proposed standards for PM, SO2, and NOX, 
might discourage the continued development of some new technologies. 
Owners/operators may view it as too risky to use new and untried or 
unproven technologies that have the potential to achieve greater 
continuous emission reductions than those required to be achieved under 
the new standards or achieve those reductions at a reduced cost. Thus, 
to encourage the continued development of new technologies that

[[Page 25069]]

show promise in achieving levels of performance comparable to those of 
existing technologies, but at lower cost or with other offsetting 
environmental or energy benefits, special provisions are needed which 
encourage the development and use of new technologies, while ensuring 
that emissions will be minimized.
    To mitigate the potential impact on emerging technologies, EPA is 
proposing to maintain similar standards to those finalized in 2006 for 
demonstration plants using innovative technologies. This should insure 
that the amended standards do not preclude the development of new 
technologies and should compensate for problems that may arise when 
applying them to commercial-scale units. Under the proposal, the 
Administrator (in consultation with DOE) would issue commercial 
demonstration permits for the first 1,000 MW of full-scale 
demonstration units of pressurized fluidized bed technology and EGUs 
using a multi-pollutant pollution control technology. Owners/operators 
of these units that are granted a commercial demonstration permit would 
be exempt from the amended standards and would instead be subject to 
less stringent emission standards. The proposed commercial 
demonstration permit standards for SO2 and NOX 
are similar to those finalized in 2006 and would avoid weakening 
existing standards while providing flexibility for innovative and 
emerging technologies. As discussed earlier, the proposed total PM 
standard of 0.034 lb/MMBtu approximates an equivalent stringency as the 
2006 filterable PM standard of 0.015 lb/MMBtu. In addition, the first 
1,000 MW of equivalent electrical capacity using advanced combustion 
controls to reduce NOX emissions would be subject to an 
emissions standard of 1.0 lb/MWh (or 1.4 (lb NOX + CO)/MWh).
    The reason we selected these particular technologies is as follows. 
Multi-pollutant controls (e.g., the Airborne Process TM, the 
CEFCO process, Eco Power's COMPLY 2000, Powerspan's ECO[supreg], ReACT 
TM, Skyonic's SkyMine[supreg], TOPS[Oslash]E SNOX 
TM, and the Pahlman process technology developed by 
Enviroscrub) offer the potential of reduced compliance costs and 
improved overall environmental performance. In addition, for boilers 
with exhaust temperatures that are too low for SCR (i.e., fluidized bed 
boilers) multi-pollutant controls are an alternative to SNCR. As 
discussed above, the use of SNCR can increase N2O emissions. 
Since multi-pollutant controls use a different mechanism to reduce 
NOX emissions, they do not necessarily result in additional 
N2O formation. However, guaranteeing that the technologies 
could achieve the proposed standards on a continuous basis might 
discourage the deployment and demonstration of these technologies at 
EGUs. Pressurized fluidized bed technology has the potential to improve 
the efficiency and reduce the environmental impact of using coal to 
generate electricity. However, it is still a relatively undeveloped 
technology and has only been deployed on a limited basis worldwide. 
Allowing new pressurized beds to demonstrate compliance with slightly 
less stringent standards will help assure the NSPS does not discourage 
the development of this technology. Advanced combustion controls allow 
for the possibility of developing EGUs with low NOX 
emissions while minimizing the need to install and operate SNCR or SCR. 
Advanced combustion controls reduce compliance costs, parasitic energy 
requirements, and ammonia emissions. Allowing the Administrator to 
approve commercial demonstration permits would limit regulatory 
impediments to improvements in combustion controls. If the 
Administrator subsequently finds that a given emerging technology 
(taking into consideration all areas of environmental impact, including 
air, water, solid waste, toxics, and land use) offers superior overall 
environmental performance, alternative standards could then be 
established by the Administrator. Technologies considered as nothing 
more than modified versions of existing demonstrated technologies will 
not be viewed as emerging technologies and will not be approved for a 
commercial demonstration permit. We are requesting comment on 
additional technologies that should be considered and the maximum 
magnitude of the demonstration permits.
5. Other Exemptions
    Because filterable PM emissions are generally negligible for 
boilers burning natural gas or low sulfur oil, eliminating the PM 
standard for owners/operators of natural gas and low sulfur oil-fired 
EGUs would both help harmonize the various steam generating unit NSPS 
and lower the compliance burden without increasing emissions. 
Similarly, eliminating the opacity standard for owners/operators of 
natural gas-fired EGUs would reduce testing and monitoring requirements 
that do not result in any emissions benefit.
    As municipal solid waste (MSW) combustors and CISWI units increase 
in size it is possible that they could generate sufficient electricity 
to become subject to the EGU NSPS. We have concluded that it is more 
appropriate to regulate these units under the CAA section 129 
regulations and are, therefore, proposing to exempt owners/operators of 
affected facilities subject to the standards of performance for large 
MSW combustors (40 CFR part 60, subpart Eb) and CISWI (40 CFR part 60, 
subpart CCCC) from complying with the otherwise applicable standards 
for pollutants that those subparts address. The PM, SO2, and 
NOX standards in 40 CFR part 60, subpart Eb, are averaged 
over a daily basis and the PM, SO2, and NOX 
standards in 40 CFR part 60, subpart CCCC, do not require CEMS and are 
based on performance test data. The standards are either approximately 
equivalent to or more stringent than the present standards in 40 CFR 
part 60, subpart Da, so this proposed amendment would simplify 
compliance for owner/operators of MSW combustors and CISWI without an 
increase in emissions.
    Similarly, in the final 2007 steam generating unit amendments (72 
FR 32,710) we inadvertently expanded the applicability of 40 CFR part 
60, subpart Db, to include industrial boilers combusting black liquor 
and distillate oil at Kraft pulp mills. Even though the distillate oil 
is generally low sulfur and would otherwise be exempt from the PM 
standards in 40 CFR part 60, subpart Db, the boilers use ESPs and the 
addition of ``not using a post-combustion technology (except a wet 
scrubber) to reduce SO2 or PM emissions'' to the oil-fired 
exemption inadvertently expanded the applicability to owners/operators 
of boilers currently subject to the standards of performance for Kraft 
pulp mills (40 CFR part 60, subpart BB). Because 40 CFR part 60, 
subpart BB, includes a PM standard, we have concluded it is more 
appropriate to only regulate PM emissions from these units under 40 CFR 
part 60, subpart BB, and are, therefore, proposing to exempt these 
units from the PM standard under 40 CFR part 60, subpart Db. The PM 
standard in 40 CFR part 60, subpart BB, is approximately equivalent in 
stringency to the one in 40 CFR part 60, subpart Db, prior to the 
recent amendments, so this proposed amendment would simplify compliance 
for owner/operators of Kraft pulp mills without an increase in 
emissions.
    We are also proposing to exempt owners/operators of IBs that meet 
the applicability requirements and that are complying with the 
SO2 standard in 40 CFR part 60, subpart Ja (standards of

[[Page 25070]]

performance for petroleum refineries) from complying with the otherwise 
applicable SO2 limit in 40 CFR part 60, subpart Db. The 
SO2 standard in 40 CFR part 60, subpart Ja, is more 
stringent than in 40 CFR part 60, subpart Db, so this proposed 
amendment would simplify compliance for owner/operators of petroleum 
refineries without an increase in pollutant emissions.

C. Changes to the Affected Facility

    The present definition of a steam generating unit under 40 CFR part 
60, subpart Da, starts at the coal bunkers and ends at the stack 
breeching. It includes the fuel combustion system (including bunker, 
coal pulverizer, crusher, stoker, and fuel burners, as applicable), the 
combustion air system, the steam generating system (firebox, boiler 
tubes, etc.), and the draft system (excluding the stack). This 
definition works well for traditional coal-fired EGUs, but does not 
account for potential efficiency improvements that have become 
available since 40 CFR part 60, subpart Da, was originally promulgated 
and are recognized through the use of output-based standards.
    The proposed rule revision to include integrated CTs and/or fuel 
cells in the definition of a steam generating unit would increase 
compliance flexibility and decrease costs. Although we are not aware of 
any EGUs that have presently integrated either device, using exhaust 
heat for reheating or preheating boiler feedwater, preheating 
combustion air, or using the exhaust directly in the boiler to generate 
steam has high theoretical incremental efficiencies. In addition, using 
exhaust heat to reheat boiler feedwater would minimize the steam 
otherwise extracted from the steam turbine used for the reheating 
process and increase the theoretical electric output for an equivalent 
sized boiler. Because the exhaust from either an integrated CT or fuel 
cell would likely not be exhausted through the primary boiler stack, we 
are requesting comment on the appropriate emissions monitoring for 
these separate stacks. Because these emissions would likely be 
relatively small compared to the boiler, we are considering allowing 
emissions to be estimated using procedures that are similar to those 
used in the acid rain trading programs as an alternative to an 
NOX CEMS. The CT or fuel cell emissions and electric output 
would be added to the boiler/steam turbine outputs.

D. Additional Proposed Amendments

    Petroleum Coke. Petroleum coke, a carbonaceous material, is a by-
product residual from the thermal cracking of heavy residual oil during 
the petroleum refining process and is a potentially useful boiler fuel. 
It has a superior heating value and lower ash content than coal and has 
historically been priced at a discount compared to coal. However, 
depending on the original crude feedstock, it may contain greater 
concentrations of sulfur and metals. At the time 40 CFR part 60, 
subpart Da, was originally promulgated, petroleum coke was not 
considered to be ``created for the purpose of creating useful heat'' 
and, hence, was not considered a ``fossil fuel.'' However, we have 
concluded that because petroleum coke has similar physical 
characteristics to coal, owners/operators of EGUs burning petroleum 
coke can cost effectively achieve the proposed standards. Due to the 
increased use of heavier crudes and more efficient processing of 
refinery residuals, U.S. and worldwide production of petroleum coke is 
increasing and is expected to continue to grow. Therefore, we expect 
owners/operators of EGUs to increase their use of petroleum coke in the 
future. Consistent with the EGU NESHAP, we are proposing to add 
petroleum coke to the definition of petroleum.
    We are requesting comment on whether petroleum coke should be added 
to the definition of coal instead of petroleum. Both 40 CFR part 60, 
subparts Db and Dc, the large and small IB NSPS, include petroleum coke 
under the definition of coal. Including petroleum coke under coal would 
be consistent with the IB NSPS. However, the proposed emission 
standards are fuel neutral and because the revised definition would 
only apply to affected facilities that begin construction, 
modification, or reconstruction after the proposal date the impact on 
the regulated community would be the same if we added petroleum coke to 
the definition of coal as it would if we added it to the definition of 
petroleum.
    Continuous Opacity Monitoring Systems (COMS). We have concluded 
that a BLDS and an ESP predictive model provide sufficient assurance 
that the filterable PM control device is operating properly such that a 
COMS is no longer necessary. Allowing this flexibility across the 
various steam generating unit NSPS would increase flexibility and 
decrease compliance costs without reducing environmental protection.
    Titles of 40 CFR part 60, subparts D and Da. We are proposing to 
simplify the titles, but not amending the applicability, of 40 CFR part 
60, subparts D and Da. The end of the titles ``for Which Construction 
Is Commenced After August 17, 1971'' and ``for Which Construction is 
Commenced After September 18, 1978'' respectively are unnecessary and 
potentially confusing.

E. Request for Comments on the Proposed NSPS Amendments

    We request comments on all aspects of the proposed amendments. All 
significant comments received will be considered in the development and 
selection of the final amendments. We specifically solicit comments on 
additional amendments that are under consideration. These potential 
amendments are described below.
    Net Output. The current output-based emission limit for PM, 
SO2, and NOX uses gross output, and the proposal 
includes standards that are based on gross energy output. In general, 
about 5 percent of station power is used internally by parasitic energy 
demands, but these parasitic loads vary on a source-by-source basis. To 
provide a greater incentive for achieving overall energy efficiency and 
minimizing parasitic loads, we would prefer to base output-based 
standards on net-energy output. However, it is our understanding that 
requiring a net output approach could result in monitoring difficulties 
and unreasonable monitoring costs at modified units. Demonstrating 
compliance with net-output based standards could be particularly 
problematic at existing units with both affected and unaffected 
facilities and units with common controls and/or stacks. Monitoring net 
output for new and reconstructed units can, on the other hand, be 
designed into the facility at low costs. To recognize the environmental 
benefit of overall environmental performance, we are considering 
establishing a net output-based emission standards for new and 
reconstructed units in the final rule in lieu of gross output-based 
standards.
    In addition to recognizing the environmental benefit of minimizing 
the internal parasitic energy demand generally, net output based 
standards would serve to further recognize the environmental benefits 
of the use of supercritical steam conditions because parasitic loads 
tend to be lower for units using supercritical steam conditions 
compared to subcritical steam conditions. Furthermore, although the 
gross efficiencies of IGCC units are projected to be several percentage 
points higher than a comparable PC facility using supercritical steam 
conditions, the parasitic energy demands at IGCC units are expected to 
be much higher at approximately 15 percent. Consequently, on a net 
output basis, the

[[Page 25071]]

efficiencies are comparable. Because we do not have continuous net 
output data available, we are considering assuming 5 percent parasitic 
losses to convert the gross output values to net output. We are 
requesting comments on the appropriate conversion factor.
    Combined Heat and Power. We are requesting comment on whether it is 
appropriate to recognize the environmental benefit of electricity 
generated by CHP units by accounting for the benefit of on-site 
generation which avoids losses from the transmission and distribution 
of the electricity. Actual line losses vary from location to location, 
but if we adopt this provision in the final rule, we are considering a 
benefit of 5 percent avoided transmission and distribution losses when 
determining the electric output for CHP units. To assure that only well 
balanced units would be eligible; this provision would be restricted to 
units where the useful thermal output is at least 20 percent of the 
total output.
    Opacity. We are requesting comment on the appropriate opacity 
monitoring procedures for owners/operators of affected facilities that 
are subject to an opacity standard but are not required to install a 
COMS. The present monitoring requirements as amended on January 20, 
2011 (76 FR 3,517) require Method 9 performance testing every 12 months 
for owners/operators of affected facilities with no visible emissions, 
performance testing every 6 months for owners/operators of affected 
facilities with maximum opacity readings of 5 percent of less, 
performance testing every 3 months for owners/operators of affected 
facilities with maximum opacity readings of between 5 to 10 percent, 
and performance testing every 45 days for owners/operators of affected 
facilities with maximum opacity readings of greater than 10 percent. We 
are requesting comment on revising the schedule to require owners/
operators of affected facilities with maximum opacity readings of 5 
percent or less to conduct annual performance testing. To further 
reduce the compliance burden for owners/operators of affected 
facilities that intermittently use backup fuels with opacity of 5 
percent or less (i.e., natural gas with distillate oil backup), we are 
requesting comment on allowing Method 9 performance testing to be 
delayed until 45 days after the next day that a fuel with an opacity 
standard is combusted. The required performance testing for owners/
operators of affected facilities with maximum opacity readings between 
5 to 10 percent would be required to be performed within 6 months. The 
required performance testing for owners/operators of affected 
facilities with maximum opacity readings greater than 10 percent would 
be required to be performed within 3 months. In addition, the alternate 
Method 22 visible observation approach requires 30 operating days of no 
visible emissions to qualify for the reduced monitoring procedures. We 
are requesting comment on only requiring either 5 or 10 days of 
observation with no visible emissions to qualify for the reduced 
periodic monitoring.
    In general, the level of filterable PM emissions and the resultant 
opacity from oil-fired steam generating units is a function of the 
completeness of fuel combustion as well as the ash content in the oil. 
Distillate oil contains negligible ash content, so the filterable PM 
emissions and opacity from distillate oil-fired steam generating units 
are primarily comprised of carbon particles resulting from incomplete 
combustion of the oil. Naturally low sulfur crude oil and desulfurized 
oils are higher quality fuels and exhibit lower viscosity and reduced 
asphaltene, ash, and sulfur content, which result in better atomization 
and improved overall combustion properties. To provide additional 
flexibility and decrease the compliance burden on affected facilities, 
we are requesting comment on whether the opacity standard should be 
eliminated for owners/operators of affected facilities burning ultra 
low sulfur (i.e., 15 ppm sulfur) distillate oil.
    We are also requesting comment on amending the opacity requirements 
for owners/operators of affected facilities using PM CEMS, but not 
complying with the PM standard under 40 CFR part 60, subpart Da. 
Owners/operators of these facilities are subject to an opacity standard 
and are required to periodically monitor opacity. We are requesting 
comment on the appropriateness of waiving all opacity monitoring for 
owners/operators of these affected facilities. In addition, we are also 
requesting comment on allowing owners/operators of 40 CFR part 60, 
subpart D, affected facilities that opt to comply with the 40 CFR part 
60, subpart Da, PM standard and qualify for the corresponding opacity 
exemption to opt back out. (Under the existing rule, once a 40 CFR part 
60, subpart D, affected facility opts to comply with the 40 CFR part 
60, subpart Da, PM standard in order to qualify for the corresponding 
opacity exemption, it cannot subsequently opt to go back to complying 
with the 40 CFR part 60, subpart D, PM standard.) Finally, we are 
requesting comment on the appropriateness of eliminating the opacity 
standard for owners/operators of 40 CFR part 60, subpart D, affected 
facilities using PM CEMS even if they are not complying with the 40 CFR 
part 60, subpart Da, PM standard. Consistent with paragraph 40 CFR 
60.11(e), as long as these facilities demonstrate continuous compliance 
with the applicable PM standard on a 3-hour average, the opacity 
standard would not apply.
    In addition, we are requesting comment on eliminating the opacity 
standard for owners/operators of affected facilities complying with a 
total PM standard of 15 ng/J (0.034 lb/MMBtu) or less that use control 
equipment parameter monitoring or some other continuous monitoring 
approach to demonstrate compliance with that standard. Based on the PM 
performance test data collected as part of the 2010 ICR, at this total 
PM emissions rate the filterable portion is expected to be 
significantly lower than the original 40 CFR part 60, subpart Da, 
filterable PM standard, 0.030 lb/MMBtu. As described in the 2006 NSPS 
amendments, at filterable PM emissions at this level, opacity is less 
useful and eliminating the standards would simplify compliance without 
decreasing environmental protection.
    IGCC Units. We are requesting comment on whether an IGCC unit that 
co-produces hydrocarbons or hydrogen should be subject to the CT NSPS 
instead of the EGU NSPS. The original rationale for including IGCC 
units in the EGU NSPS is that it is simply another process for 
converting coal to electricity. However, an IGCC that co-produces 
hydrocarbons or hydrogen would convert a substantial portion of the 
original energy in the coal to useful chemicals instead of to 
measurable useful electric and thermal output. Using net-output based 
standards in this situation would be difficult because a portion of the 
parasitic load would be attributed to the production of the useful 
chemicals and it would not be possible to apportion this easily. To 
avoid owners/operators from producing a small amount of hydrocarbons/
hydrogen to avoid being subject to 40 CFR part 60, subpart Da, we are 
requesting comment on the percentage of coal that must be converted to 
useful chemical products to quality for regulation under the stationary 
CT NSPS. We are presently considering between 10 to 20 percent. We are 
also requesting comment on whether there is a way to effectively 
account for the parasitic losses such attributable to production of the 
useful chemicals.
    Elimination of Existing References. To simplify compliance and 
improve the

[[Page 25072]]

readability of 40 CFR part 60, subpart Da, we are requesting comment on 
deleting the ``emergency condition'' requirement for the SO2 
standard exemption, references to percent reductions for NOX 
and PM, references to solvent refined coal, and the existing commercial 
demonstration permit references. The emergency condition requirement 
was originally included in 40 CFR part 60, subpart Da, as an 
alternative to excluding periods of malfunction. The provision was 
intended to avoid power supply disruptions while also minimizing 
operation of affected facilities without operation of SO2 
controls. However, the reliability of FGD technology has been 
demonstrated since 40 CFR part 60, subpart Da, was originally 
promulgated and malfunctions are uncommon events. Furthermore, the 
Transport Rule provides a financial incentive to operate SO2 
control equipment at all times. Therefore, we would delete references 
to the emergency condition requirement and simply exclude periods of 
malfunction from the SO2 standard for owners/operators of 
affected facilities presently subject to 40 CFR part 60, subpart Da.
    The 1990 CAA amendments removed the requirement that standards be 
based on a percent reduction. The percent reduction requirements for 
NOX and PM have been superseded by the numerical limits for 
owners/operators of existing units and deleting these references would 
improve the readability of the subpart. Similarly, we are not aware of 
any affected facility burning solvent refined coal or operating under 
the existing commercial demonstration permit. Because these provisions 
have been superseded, deleting these references would improve the 
readability of the subpart.
    The IB NSPS currently does not credit fuel pretreatment toward 
compliance with the SO2 percent reduction standard unless 
the fuel pretreatment results in a 50 percent or greater reduction in 
the potential SO2 emissions rate and results in an 
uncontrolled SO2 emissions rate of equal to less than 0.60 
lb/MMBtu. We are requesting comment on whether these restrictions 
discourage the development and use of cost-effective fuel pretreatment 
technologies and increase costs to the regulated community. To the 
extent that this restriction could be eliminated without adversely 
impacting protection of the environment, we are considering eliminating 
this restriction. We are also requesting comment on other provisions in 
the steam generating unit NSPS that could be eliminated to reduce 
regulatory burden without decreasing environmental protection.
    The large IB NSPS (40 CFR part 60, subpart Db) currently includes 
regulatory language for standards for boilers burning MSW. This 
language was included to assure the broad applicability of 40 CFR part 
60, subpart Db. However, subsequent to the original promulgation of 40 
CFR part 60, subpart Db, EPA promulgated specific standards for MWCs 
and exempted owners/operators of MWCs from 40 CFR part 60, subpart Db. 
We are requesting comment on deleting all references to MSW in 40 CFR 
part 60, subpart Db. This would simplify compliance and readability of 
the rule without increasing emissions to the environment. Owners/
operators of these units would still be subject to emission standards 
under 40 CFR part 60, subpart Db, if they stop burning MSW.
    Coal Refuse. The high ash and corresponding low Btu content of coal 
refuse results in lower efficiencies than comparable coal-fired EGUs. 
Therefore, we are requesting comment on the environmental impact of 
subcategorizing coal refuse-fired EGUs and maintaining the existing 
NOX standard of 1.0 lb/MWh (or 1.4 lb [NOX + CO]/
MWh) for owners/operators of these units.
    Temporary Boilers. On occasion, owners/operators of industrial 
facilities need to bring in temporary boilers for steam production for 
short-term use while the primary steam boilers are not available. The 
existing testing and monitoring requirements for IB may not be 
appropriate for temporary boilers used for less than 30 days. We intend 
to establish alternate testing and monitoring requirements for owners/
operators of temporary IBs and are requesting comment on the 
appropriate requirements.

IX. Summary of Cost, Environmental, Energy, and Economic Impacts of 
This Proposed NSPS

    In setting the standards, the CAA requires us to consider 
alternative emission control approaches, taking into account the 
estimated costs and benefits, as well as the energy, solid waste and 
other effects. EPA requests comment on whether it has identified the 
appropriate alternatives and whether the proposed standards adequately 
take into consideration the incremental effects in terms of emission 
reductions, energy and other effects of these alternatives. EPA will 
consider the available information in developing the final rule.
    The costs, environmental, energy, and economic impacts are 
typically expressed as incremental differences between the impacts on 
owners/operators of units complying with the proposed amendments 
relative to complying with the current NSPS emission standards (i.e., 
baseline). However, for EGUs this would not accurately represent actual 
costs and benefits of the proposed amendments. Requirements of the NSR 
program often result in new EGUs installing controls beyond what is 
required by the existing NSPS. In addition, owners/operators of new 
EGUs subject to the requirements of the Transport Rule will likely 
elect to minimize operating costs by operating at SO2 and 
NOX emission rates lower than what is required by the 
existing NSPS. Finally, the proposed EGU NESHAP PM and SO2 
standards for new EGUs are as stringent as or more stringent than the 
proposed NSPS amendments, and we have concluded that there are no costs 
or benefits associated with these amendments. We are requesting comment 
on this conclusion.
    To establish the regulatory baseline for NOX emissions, 
we reviewed annual NOX emission rates for units operating at 
levels below the existing NSPS NOX standard that commenced 
operation between 2005 and 2008 and that reported both NOX 
emissions and gross electric output data to CAMD. The 2009 average 
annual NOX emissions rate for these units was 0.61 lb/MWh. 
To account for the variability in performance of presently used 
NOX controls, we concluded that 30-day averages are 
typically \1/4\ to \1/3\ higher than annual average emission rates and 
used 0.80 lb/MWh as the baseline. This represents an approximate 12 
percent reduction in the growth of NOX emissions from new 
units that would be subject to the proposed standards. We have 
concluded that a combined NOX/CO standard would have similar 
impacts because CO controls are based on readily available combustion 
controls. The additional monitoring costs for a combined standard would 
include additional CEMS certification because many facilities currently 
have CO CEMS for operational control.
    Although multiple coal-fired EGUs have recently commenced operation 
and several are currently under construction, no new coal-fired EGUs 
have commenced construction in either 2009 or 2010. In addition, 
forecasts of new generation capacity from both the EIA and the Edison 
Electric Institute do not project any new coal-fired EGUs being 
constructed in the short term. This is an indication that, in the near 
term, few new coal-fired EGUs will be subject to the NSPS amendments. 
Because the use of natural gas in boiler/

[[Page 25073]]

steam turbine-based EGUs is an inefficient use of natural gas to 
generate electricity, all new natural gas-fired EGUs built in the 
foreseeable future will most likely be combined cycle units or CT 
peaking units and, thus, not subject to 40 CFR part 60, subpart Da, but 
instead subject to the NSPS for stationary CTs (40 CFR part 60, subpart 
KKKK). Furthermore, because of fuel supply availability and cost 
considerations, we assumed that no new oil-fired EGUs will be built 
during the next 5 years.
    Therefore, we are not projecting that any new, reconstructed, or 
modified steam generating units would become subject to the proposed 
amendments over the next 5 years. Even though we are not projecting any 
impacts from the proposed amendments, in the event a new steam 
generating units does become subject the proposed amendments we have 
concluded that the proposed amendments would be appropriate. For more 
information on these impacts, please refer to the economic impact 
analysis and technical support documents in the public docket.

X. Impacts of These Proposed Rules

A. What are the air impacts?

    Under the proposed Toxics Rule, EPA projects annual HCl emissions 
reductions of 91 percent in 2015, Hg emissions reductions of 79 percent 
in 2015, and PM2.5 emissions reductions of 29 percent in 
2015. In addition, EPA projects SO2 emission reductions of 
53 percent, annual NOX emissions reductions of 7 percent, 
and annual CO2 reductions of 1 percent from the power sector 
by 2015, relative to the base case. See Table 21.

                                              Table 21--Summary of Power Sector Emissions Reductions (TPY)
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                                               PM2.5
                                                           SO2 (million    NOX (million   Mercury (tons)   HCl (thousand     (thousand     CO2 (million
                                                               tons)           tons)                           tons)           tons)      metric tonnes)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Base Case...............................................             3.9             2.0              29              78             286           2,243
Proposed Toxics Rule....................................             1.8             1.9               6              10             202           2,219
Change..................................................            -2.1            -0.1           -23.0             -68           -83.2           -24.2
--------------------------------------------------------------------------------------------------------------------------------------------------------

B. What are the energy impacts?

    Under the provisions of this proposed rule, EPA projects that 
approximately 9.9 GW of coal-fired generation (roughly 3 percent of all 
coal-fired capacity and 1% of total generation capacity in 2015) may be 
removed from operation by 2015. These units are predominantly smaller 
and less frequently used generating units dispersed throughout the area 
affected by the rule. 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 keep these units operational.
    EPA also projects fuel price increases resulting from the proposed 
Toxics Rule. Average retail electricity prices are shown to increase in 
the continental U.S. by 3.7 percent in 2015. This is generally less of 
an increase than often occurs with fluctuating fuel prices and other 
market factors. Related to this, the average delivered coal price 
increases by less than 1 percent in 2015 as a result of shifts within 
and across coal types. EPA also projects that electric power sector-
delivered natural gas prices will increase by about 1 percent over the 
2015-2030 timeframe and that natural gas use for electricity generation 
will increase by about less than 300 billion cubic feet (BCF) over that 
horizon. 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 20 million tons in 2015 from 
base case levels, which is less than 2 percent of total coal produced 
for the electric power sector in that year.

C. What are the compliance costs?

    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 proposed Toxics Rule HAP emission standards. In 
simple terms, these costs are the resource costs of what the power 
industry will directly expend to comply with EPA's requirements.
    EPA projects that the annual incremental compliance cost of the 
proposed Toxics Rule is $10.9 billion in 2015 ($2007). The annualized 
incremental cost is the projected additional cost of complying with the 
proposed 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.
    End-use energy efficiency can be an important part of a compliance 
strategy for this regulation. It can reduce the cost of compliance, 
lower consumer costs, reduce emissions, and help to ensure reliability 
of the U.S. power system. Policies to promote end-use energy efficiency 
are largely outside of EPA's direct control. However this rule can 
provide an incentive for action to promote energy efficiency. To 
examine the potential impacts of Federal and state energy efficiency 
policies, EPA used the Integrated Planning Model (IPM).
    An illustrative Energy Efficiency Scenario was developed and run as 
a sensitivity for both the Base Case and the Toxics Rule Case. The 
illustrative Energy Efficiency Case assumed adoption of two key energy 
efficiency policies. First, it assumed that states adopted rate-payer 
funded energy efficiency programs, such as energy efficiency resource 
standards, integrated resource planning and demand side management 
plans. Examples of energy efficiency programs that might be driven by 
these policies include rebate programs for efficient products and state 
programs to provide technical assistance and information for energy 
efficient home retrofits. The electricity demand reduction that could 
be gained from these programs was taken from work done by Lawrence 
Berkley National Laboratory (LBNL).\179\ Second, the Department of 
Energy (DOE) provided estimates of the demand reductions that could be 
achieved from implementation of appliance efficiency standards mandated 
by existing statutes but not yet implemented (appliance standards that 
have been implemented are in the base case.) EPA assumed that these 
policies are used beyond the timeframe of the DOE and LBNL estimates 
(2035

[[Page 25074]]

and 2020 respectively) so that their impacts continue through 2050. 
Table 22 below gives the electricity demand reductions that these two 
policies would yield.
---------------------------------------------------------------------------

    \179\ The Shifting Landscape of Ratepayer Funded Energy 
Efficiency in the U.S., Galen Barbose et al., October 2009, Lawrence 
Berkeley National Laboratory, LBNL-2258E.

                                     Table 22--Energy Efficiency Sensitivity Results: Electricity Demand Reductions
--------------------------------------------------------------------------------------------------------------------------------------------------------
                         (all in TWh)                              2009         2012         2015         2020         2030         2040         2050
--------------------------------------------------------------------------------------------------------------------------------------------------------
Ratepayer-funded EE Programs.................................  ...........           59          110          174          198          198          198
% of U.S. Demand.............................................  ...........         1.5%         2.7%         4.1%         4.2%         3.9%         3.6%
Federal Appliance Standards..................................  ...........            0            6           52          112          114          124
% of U.S. Demand.............................................  ...........         0.0%         0.2%         1.2%         2.4%         2.2%         2.2%
Total EE Demand Reductions...................................  ...........           59          117          226          310          312          322
% of U.S. Demand.............................................  ...........         1.5%         2.9%         5.3%         6.6%         6.1%         5.8%
U.S. Electricity Demand (EPA Reference)......................        3,838        4,043        4,086        4,302        4,703        5,113        5,568
Average Annual Growth Rate (2009 to 20xx)....................  ...........  ...........        1.05%        1.04%        0.97%        0.93%        0.91%
Net Demand after EE..........................................        3,838        3,984        3,969        4,076        4,392        4,801        5,246
Average Annual Growth Rate (2009 to 20xx)....................  ...........  ...........        0.56%        0.55%        0.64%        0.73%        0.77%
--------------------------------------------------------------------------------------------------------------------------------------------------------

    As shown, these policies are estimated to result in a moderate 
reduction in U.S. electricity demand climbing to over five percent by 
2020 and averaging over five percent from 2020 to 2050. These 
reductions lower annual average electricity demand growth (from 2009 
historic data) through 2020 relative to the reference forecast from 
1.04 percent to 0.55 percent.
    The effects of the Energy Efficiency Scenario on the projected 
total electricity generating costs of the power sector are shown below 
in Table 23. In this table we see the projected costs in the Base and 
Toxics Rule Cases with and without energy efficiency.

                     Table 23--Effect of Energy Efficiency Policy on Generation System Costs
----------------------------------------------------------------------------------------------------------------
           Total costs (billion 2007$)--IPM + Total EE                 2015            2020            2030
----------------------------------------------------------------------------------------------------------------
Base............................................................             144             155             200
Base + EE.......................................................             142             150             190
Toxics Rule.....................................................             155             165             210
Toxics Rule + EE................................................             153             159             199
1. Increment (Base to Base + EE)................................              -2              -5             -11
2. Increment (Toxics Rule to Toxics Rule + EE)..................              -2              -6             -11
3. Increment (Base to Toxics Rule)..............................              11              10              10
4. Increment (Base + EE to Toxics Rule + EE)....................              11               9               9
5. Increment (Base to Toxics Rule) to (Base + EE to Toxics Rule                0              -1              -1
 + EE)..........................................................
6. Increment (Base to Toxics Rule + EE).........................               9               4              -1
----------------------------------------------------------------------------------------------------------------

    In this analysis, the costs of the energy efficiency policies are 
treated as a component of the cost of generating electricity and are 
imbedded in the costs seen in Table 23. The modeling estimated that 
these energy efficiency policies would reduce the total cost of 
implementing the rule by billions of dollars. EPA looked at a case in 
which these energy efficiency policies were in place with and without 
the Toxics Rule. As Table 23 shows, with or without the Toxics Rule, 
energy efficiency policies reduce the overall costs to generate 
electricity. The cost reductions increase over time. When comparing the 
Toxics Rule Case without energy efficiency to the Toxics Rule Case with 
energy efficiency, the analysis shows that these energy efficiency 
policies could reduce overall system costs by $2 billion in 2015, $6 
billion in 2020, and $11 billion in 2030.
    The energy savings driven by these energy efficiency policies, and 
corresponding lower levels of demand, translate into reductions in 
electricity prices. EPA's modeling shows that the Toxics Rule increases 
retail prices by 3.7 percent, 2.6 percent and 1.9 percent in 2015, 2020 
and 2030, respectively, relative to the base case. If energy efficiency 
policies are implemented, the price increase would be smaller in 2015 
when retail prices would increase by 3.3 percent. In 2020 and 2030 the 
reduced demand for electricity is sufficient to reduce the retail price 
of electricity relative to the Base Case even with the Toxics Rule. If 
the Toxics Rule is implemented with energy efficiency, retail 
electricity prices decrease by about 1.6 percent in 2020 and by about 
2.3 percent in 2030 relative to the Base.\180\ The effect on average 
electricity bills, however, may fall more than these percentages as 
energy efficiency means that less electricity will be used by consumers 
of electricity.
---------------------------------------------------------------------------

    \180\ Source: EPA's Retail Electricity Price Model.
---------------------------------------------------------------------------

    In the Energy Efficiency Cases, IPM projects considerably more 
plant retirements than in the Base and Policy Cases. The Base Case with 
Energy Efficiency in 2020 shows twice as much capacity retiring, and 
more than double the capacity of coal plant retirements as the Base 
Case without energy efficiency. The Toxics Rule would increase the 
amount of capacity retired over the Base Case by 8 GW. If the energy 
efficiency policies were imposed as the power sector was taking action 
to come into compliance, the effect of the Toxics Rule on plant 
retirements would be greater with an additional 25 GW of

[[Page 25075]]

retirements in 2020. These results are shown in Table 24 below.

                              Table 24--Effect of Energy Efficiency on Retirements
----------------------------------------------------------------------------------------------------------------
              Retirements Grand Total & (Coal) (GW)                    2015            2020            2030
----------------------------------------------------------------------------------------------------------------
Base............................................................          27 (5)          27 (5)          27 (5)
Base + EE.......................................................         38 (12)         54 (12)         53 (12)
Toxics Rule.....................................................         35 (15)         35 (14)         35 (14)
Toxics Rule + EE................................................         47 (25)         60 (24)         60 (24)
1. Increment (Base to Base + EE)................................          11 (7)          27 (7)          26 (7)
2. Increment (Toxics Rule to Toxics Rule + EE)..................         11 (10)         25 (10)         24 (10)
3. Increment (Base to Toxics Rule)..............................          9 (10)           8 (9)           8 (9)
4. Increment (Base + EE to Toxics Rule + EE)....................          9 (13)          6 (12)          6 (12)
5. Increment (Base to Toxics Rule) to (Base + EE to Toxics Rule          0 (3.0)          -2 (3)          -2 (3)
 + EE)..........................................................
6. Increment (Base to Toxics Rule + EE).........................         20 (20)         33 (19)         32 (19)
----------------------------------------------------------------------------------------------------------------

    In effect, the timely adoption and implementation of energy 
efficiency policies would augment currently projected reserve 
capacities that are instrumental to assuring system reliability.
    The addition of energy efficiency policies during and beyond the 
Toxics Rule compliance period can result in very modest reductions in 
air emissions. This is largely due to lower levels of electricity 
generation. As a result, with energy efficiency policies the Toxics 
Rule would achieve reductions of approximately an additional 520 pounds 
of Hg emissions, an additional 80,000 tons of SO2, and an 
additional 110,000 tons of NOX in 2020.
    Although EPA cannot mandate energy efficiency policies, the 
positive effects of these policies on the cost of rule to industry and 
consumers could be a strong incentive to undertake them as a part of an 
overall compliance strategy.
    Table 25 presents estimated breakouts of the cost of reducing 
certain key pollutants under the Toxics Rule. Because many of the 
strategies to reduce pollutants are multi-pollutant in nature, it is 
not possible to create a technology-specific breakout of costs (e.g. a 
baghouse reduces PM2.5 as well as Hg, it also reduces the 
cost of using additional sorbents to reduce acid gases or further 
reduce Hg). Costs were first calculated by using representative unit 
costs for each control option. These costs were then multiplied by the 
amount of capacity that employed the given control option. Costs were 
then pro-rated amongst the pollutants that a given technology reduced. 
This pro-ration was based on rough estimates of the percentage 
reduction expected for a given pollutant (e.g. because a baghouse alone 
removes significant amounts of PM2.5 and has a much smaller 
Hg reduction, most of the baghouse cost was assigned to 
PM2.5, in the case of ACI (which often includes a baghouse) 
reductions of Hg and fine PM were similar, therefore costs were pro-
rated more equally). Since total costs from the bottom up calculation 
did not exactly match our total modeled costs, the pollutant by 
pollutant costs were then pro-rated to equal the total model costs.

                               Table 25--Breakouts of Costs by Control Measure and Pollutant for the Proposed Toxics Rule
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                Dry FGD +                                            Scrubber    Waste coal
                                                                    FF          DSI           FF          ACI        upgrade        FGD         Total
--------------------------------------------------------------------------------------------------------------------------------------------------------
Total (2007 $MM)...............  Capital.....................        1,421          428        1,092        1,498          669           94        5,201
                                 FOM.........................          252           71           41           45            0           20          431
                                 VOM                                   377        1,241          105          627            0           66        2,416
                                 2015 Annual Capital + FOM +         2,050        1,740        1,238        2,173          669          179        8,048
                                  VOM.
Cost Share.....................  HCl.........................          29%          56%           0%           0%          52%          29%  ...........
                                 Hg..........................          10%           0%          10%          51%           0%          10%  ...........
                                 PM2.5.......................          32%           0%          90%          49%           0%          32%  ...........
                                 SO2.........................          29%          44%           0%           0%          48%          29%  ...........
Total Annual Costs, 2015 (2007   HCL.........................          588          979            0            0          347           51        1,965
 $MM).
                                 Hg..........................          205            0          124        1,106            0           18        1,453
                                 PM2.5.......................          654            0        1,114        1,067            0           57        2,892
                                 SO2.........................          603          761            0            0          322           53        1,739
                                                              ------------------------------------------------------------------------------------------
                                  TOTAL......................        2,050        1,740        1,238        2,173          669          179        8,048
--------------------------------------------------------------------------------------------------------------------------------------------------------


 
                                                                                                                                               General
                                                                                                                                               range of
                                   Capital + FOM + VOM Costs    Fuel cost    Total cost    Share of     Capital        Tons     $/ton ($/lb   costs from
                                                                                          total cost     share       reduced      for Hg)     other MACT
                                                                                                                                                rules
--------------------------------------------------------------------------------------------------------------------------------------------------------
Acid Gasses (HCl + HCN + HF)...  1,965.......................        1,064        3,029          24%          37%      106,038      $18,529  $2,500-$55,
                                                                                                                                                     000
Hg.............................  1,453.......................          825        2,277          18%          49%           18      $40,428  $1,250-$55,
                                                                                                                                                     200
PM2.5..........................  2,892.......................          357        3,249          36%          74%       83,246      $34,742  $1,600-$55,
                                                                                                                                                     000
SO2............................  1,739.......................          645        2,384          22%          44%    2,050,871         $848  $540-$5,100
                                ------------------------------------------------------------------------------------------------------------------------
    Total......................  8,048.......................        2,892       10,940         100%  ...........  ...........  ...........  ...........
--------------------------------------------------------------------------------------------------------------------------------------------------------


[[Page 25076]]

D. What are the economic impacts?

    For this proposed rule, EPA analyzed the costs using IPM. IPM is a 
dynamic linear programming model that can be used to examine the 
economic impacts of air pollution control policies for a variety of HAP 
and other pollutants throughout the contiguous U.S. for the entire 
power system.
    Documentation for IPM can be found in the docket for this 
rulemaking or at http://www.epa.gov/airmarkets/progsregs/epa-ipm/index.html.
    EPA also included an analysis of impacts of the proposed rule to 
industries outside of the electric power sector by using the Multi-
Market Model. This model is a partial equilibrium model that includes 
100 sectors that cover energy, manufacturing, and service applications 
and is designed to capture the short-run effects associated with an 
environmental regulation. It was used to estimate economic impacts for 
the recently promulgated Industrial Boiler major and area source 
standards and CISWI standard.
    We use the Multi-Market model to estimate the social cost of the 
proposed rule. Using this model, we estimate the social costs of the 
proposal to be $10.9 billion (2007$), which is almost identical to the 
compliance costs. The usefulness of a Multi-Market model in predicting 
the estimated effects is limited because the electric power sector 
affects all sectors of the economy. For the final rule, we will be 
refining the social cost estimates with general equilibrium models, 
including an assessment with our upgraded CGE model, EMPAX. Commenters 
are encouraged to provide other general equilibrium model platforms and 
to provide other information to refine the social cost assessments for 
the final rule.
    EPA also performed a screening analysis for impacts on small 
entities by comparing compliance costs to sales/revenues (e.g., sales 
and revenue tests). EPA's analysis found the tests were typically 
higher than 1 percent for small entities included in the screening 
analysis. EPA has prepared an Initial Regulatory Flexibility Analysis 
(IRFA) that discusses alternative regulatory or policy options that 
minimize the rule's small entity impacts. It includes key information 
about key results from the SBAR panel.
    Although a stand-alone analysis of employment impacts is not 
included in a standard cost-benefit analysis, the current economic 
climate has led to heightened concerns about potential job impacts. 
Such an analysis is of particular concern in the current economic 
climate as sustained periods of excess unemployment may introduce a 
wedge between observed (market) wages and the social cost of labor. In 
such conditions, the opportunity cost of labor required by regulated 
sectors to bring their facilities into compliance with an environmental 
regulation may be lower than it would be during a period of full 
employment (particularly if regulated industries employ otherwise idled 
labor to design, fabricate, or install the pollution control equipment 
required under this proposed rule). For that reason, EPA also includes 
estimates of job impacts associated with the proposed rule. EPA 
presents an estimate of short-term employment opportunities as a result 
of increased demand for pollution control equipment. Overall, the 
results suggest that the proposed rule could support a net of roughly 
31,000 job-years \181\ in direct employment impacts in 2015.
---------------------------------------------------------------------------

    \181\ 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.
---------------------------------------------------------------------------

    The basic approach to estimate these employment impacts involved 
using projections from IPM from the proposed rule analysis such as the 
amount of capacity that will be retrofit with control technologies, for 
various energy market implications, along with data on labor and 
resource needs of new pollution controls and labor productivity from 
secondary sources, to estimate employment impacts for 2015. For more 
information, please refer to the TSD for this analysis, ``Employment 
Estimates of Direct Labor in Response to the Proposed Toxics Rule in 
2015.''
    EPA relied to Morgenstern, et al. (2002), identify three economic 
mechanisms by which pollution abatement activities can indirectly 
influence jobs:
    Higher production costs raise market prices, higher prices reduce 
consumption, and employment within an industry falls (``demand 
effect'');
    Pollution abatement activities require additional labor services to 
produce the same level of output (``cost effect''); and
    Post regulation production technologies may be more or less labor 
intensive (i.e., more/less labor is required per dollar of output) 
(``factor-shift effect'').
    Using plant-level Census information between the years 1979 and 
1991, Morgenstern, et al., estimate the size of each effect for four 
polluting and regulated industries (petroleum, plastic material, pulp 
and paper, and steel). On average across the four industries, each 
additional $1 million spending on pollution abatement results in an 
small net increase of 1.6 jobs; the estimated effect is not 
statistically significant different from zero. As a result, the authors 
conclude that increases in pollution abatement expenditures do not 
necessarily cause economically significant employment changes. The 
conclusion is similar to Berman and Bui (2001) who found that increased 
air quality regulation in Los Angeles did not cause large employment 
changes.\182\ For more information, please refer to the RIA for this 
proposed rule.
---------------------------------------------------------------------------

    \182\ For alternative views in economic journals, see Henderson 
(1996) and Greenstone (2002).
---------------------------------------------------------------------------

    The ranges of job effects calculated using the Morgenstern, et al., 
approach are listed in Table 26.

                            Table 26--Range of Job Effects for the Electricity Sector
----------------------------------------------------------------------------------------------------------------
                                          Estimates using Morgenstern, et al. (2001)
                                      --------------------------------------------------   Factor shift effect
                                            Demand effect             Cost effect
----------------------------------------------------------------------------------------------------------------
Change in Full-Time Jobs per Million   -3.56..................  2.42...................  2.68.
 Dollars of Environmental Expenditure
 \a\.
Standard Error.......................  2.03...................  1.35...................  0.83.
EPA estimate for Proposed Rule \b\...  -45,000 to +2,500......  +4,700 to 24,000.......  +200 to 32,000.
----------------------------------------------------------------------------------------------------------------
\a\ Expressed in 1987 dollars. See footnote a from Table 9-3 of the RIA for inflation adjustment factor used in
  the analysis.
\b\ According to the 2007 Economic Census, the electric power generation, transmission and distribution sector
  (NAICS 2211) had approximately 510,000 paid employees.


[[Page 25077]]

    EPA recognizes there may be other job effects which are not 
considered in the Morgenstern, et al., study. Although EPA has 
considered some economy-wide changes in industry output as shown 
earlier with the Multi-Market model, we do not have sufficient 
information to quantify other associated job effects associated with 
this rule. EPA solicits comments on information (e.g., peer-reviewed 
journal articles) and data to assess job effects that may be 
attributable to this rule.

E. What are the benefits of this proposed rule?

    We estimate the monetized benefits of this proposed regulatory 
action to be $59 billion to $140 billion (2007$, 3 percent discount 
rate) in 2016. The monetized benefits of the proposed regulatory action 
at a 7 percent discount rate are $53 billion to $130 billion (2007$). 
These estimates reflect the economic value of the Hg benefits as well 
as the PM2.5 and CO2-related co-benefits.
    Using alternate relationships between PM2.5 and 
premature mortality supplied by experts, higher and lower benefits 
estimates are plausible, but most of the expert-based estimates fall 
between these two estimates.\183\ A summary of the monetized benefits 
estimates at discount rates of 3 percent and 7 percent is in Table 27 
of this preamble.
---------------------------------------------------------------------------

    \183\ 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.

       Table 27--Summary of the PM2.5 Monetized Co-Benefits Estimates for the Proposed Toxics Rule in 2016
                                             [Billions of 2007$] \a\
----------------------------------------------------------------------------------------------------------------
                                          Estimated emission      Monetized PM2.5 co-      Monetized PM2.5 co-
                                         reductions (million     benefits (3% discount    benefits (7% discount
                                            tons per year)               rate)                    rate)
----------------------------------------------------------------------------------------------------------------
PM2.5 Precursors
SO2..................................  2.1....................  $58 to $140............  $53 to $130.
                                      --------------------------------------------------------------------------
    Total............................  .......................  $58 to $140............  $53 to $130.
----------------------------------------------------------------------------------------------------------------
\a\ All estimates are for the implementation year (2016), and are rounded to two significant figures. All fine
  particles are assumed to have equivalent health effects, but the benefit-per-ton estimates vary between
  precursors because each ton of precursor reduced has a different propensity to form PM2.5. Benefits from
  reducing HAP are not included.

    These benefits estimates represent the total monetized human health 
benefits for populations exposed to less PM2.5 in 2016 from 
controls installed to reduce air pollutants in order to meet these 
standards. These estimates are calculated as the sum of the monetized 
value of avoided premature mortality and morbidity associated with 
reducing a ton of PM2.5 and PM2.5 precursor 
emissions. To estimate human health benefits derived from reducing 
PM2.5 and PM2.5 precursor emissions, we used the 
general approach and methodology laid out in Fann, et al. (2009).\184\
---------------------------------------------------------------------------

    \184\ 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.
---------------------------------------------------------------------------

    To generate the benefit-per-ton estimates, we used a model to 
convert emissions of PM2.5 precursors into changes in 
ambient PM2.5 levels and another model to estimate the 
changes in human health associated with that change in air quality. 
Finally, the monetized health benefits were divided by the emission 
reductions to create the benefit-per-ton estimates. Even though we 
assume that all fine particles have equivalent health effects, the 
benefit-per-ton estimates vary between precursors because each ton of 
precursor reduced has a different propensity to form PM2.5. 
For example, SOX has a lower benefit-per-ton estimate than 
direct PM2.5 because it does not form as much 
PM2.5, thus the exposure would be lower, and the monetized 
health benefits would be lower.
    For context, it is important to note that the magnitude of the PM 
benefits is largely driven by the concentration response function for 
premature mortality. Experts have advised EPA to consider a variety of 
assumptions, including estimates based both on empirical 
(epidemiological) studies and judgments elicited from scientific 
experts, to characterize the uncertainty in the relationship between 
PM2.5 concentrations and premature mortality. For this 
proposed rule we cite two key empirical studies, one based on the 
American Cancer Society cohort study \185\ and the extended Six Cities 
cohort study.\186\ In the Regulatory Impacts Analysis (RIA) for this 
proposed rule, which is available in the docket, we also include 
benefits estimates derived from expert judgments and other assumptions.
---------------------------------------------------------------------------

    \185\ 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.
    \186\ Laden et al., 2006. ``Reduction in Fine Particulate Air 
Pollution and Mortality.'' American Journal of Respiratory and 
Critical Care Medicine. 173: 667-672.
---------------------------------------------------------------------------

    This analysis does not include the type of detailed uncertainty 
assessment found in the 2006 PM2.5 NAAQS RIA because we lack 
the necessary air quality input and monitoring data to run the benefits 
model. However, the 2006 PM2.5 NAAQS benefits analysis \187\ 
provides an indication of the sensitivity of our results to various 
assumptions.
---------------------------------------------------------------------------

    \187\ U.S. Environmental Protection Agency, 2006. Final 
Regulatory Impact Analysis: PM2.5 NAAQS. Prepared by 
Office of Air and Radiation. October. Available on the Internet at 
http://www.epa.gov/ttn/ecas/ria.html.
---------------------------------------------------------------------------

    It should be emphasized that the monetized benefits estimates 
provided above do not include benefits from several important benefit 
categories, including reducing other air pollutants, ecosystem effects, 
and visibility impairment. The benefits from reducing various HAP have 
not been monetized in this analysis, including reducing 68,000 tons of 
HCl, and 3,200 tons of other metals each year. Although we do not have 
sufficient information or modeling available to provide monetized 
estimates for this rulemaking, we include a qualitative assessment of 
the health effects of these air pollutants in the RIA for this proposed 
rule, which is available in the docket.

[[Page 25078]]



   Table 28--Summary of the Monetized Benefits, Social Costs, and Net
                 Benefits for the Proposed Rule in 2016
                         [Millions of 2006$] \a\
------------------------------------------------------------------------
                                   3% Discount rate    7% Discount rate
------------------------------------------------------------------------
Total Monetized Benefits \b\....  $59,000 to          $53,000 to
                                   $140,000.           $130,000.
Hg-related Benefits \c\.........  $4.1 to $5.9......  $0.45 to $0.89.
CO2-related Benefits............  $570..............  $570.
PM2.5-related Co-benefits \d\...  $59,000 to          $53,000 to
                                   $140,000.           $120,000.
Total Social Costs \e\..........  $10,900...........  $10,900.
Net Benefits....................  $48,000 to          $42,000 to
                                   $130,000.           $130,000.
                                 ---------------------------------------
Non-monetized Benefits..........  Visibility in Class I areas.
                                  Cardiovascular effects of Hg exposure.
                                  Other health effects of Hg exposure.
                                  Ecosystem effects.
                                  Commercial and non-freshwater fish
                                   consumption.
------------------------------------------------------------------------
\a\ All estimates are for 2016, and are rounded to two significant
  figures. The net present value of reduced CO2 emissions are calculated
  differently than other benefits. The same discount rate used to
  discount the value of damages from future emissions (SCC at 5, 3, 2.5
  percent) is used to calculate net present value of SCC for internal
  consistency. This table shows monetized CO2 co-benefits at discount
  rates at 3 and 7 percent that were calculated using the global average
  SCC estimate at a 3 percent discount rate because the interagency
  workgroup on this topic deemed this marginal value to be the central
  value. In section 6.6 of the RIA we also report the monetized CO2 co-
  benefits using discount rates of 5 percent (average), 2.5 percent
  (average), and 3 percent (95th percentile).
\b\ The total monetized benefits reflect the human health benefits
  associated with reducing exposure to MeHg, PM2.5, and ozone.
\c\ Based on an analysis of health effects due to recreational
  freshwater fish consumption.
\d\ The reduction in premature mortalities account for over 90 percent
  of total monetized PM2.5 benefits.
\e\ Social costs are estimated using the MultiMarket model, in order to
  estimate economic impacts of the proposal to industries outside the
  electric power sector. Details on the social cost estimates can be
  found in Chapter 9 and Appendix E of the RIA.

    For more information on the benefits and cost analysis, please 
refer to the RIA for this rulemaking, which is available in the docket.

XI. Public Participation and Request for Comment

    We request comment on all aspects of this proposed rule.
    During this rulemaking, we conducted outreach to small entities and 
convened a SBAR Panel to obtain advice and recommendation of 
representatives of the small entities that potentially would be subject 
to the requirements of this proposed rule. As part of the SBAR Panel 
process we conducted outreach with representatives from various small 
entities that would be affected by this proposed rule. We met with 
these SERs to discuss the potential rulemaking approaches and potential 
options to decrease the impact of the rulemaking on their industries/
sectors. We distributed outreach materials to the SERs; these materials 
included background, project history, CAA section 112 overview, 
constraints on rulemaking, affected facilities, data, rulemaking 
options under consideration, potential control technologies and 
estimated costs, applicable small entity definitions, small entities 
potentially subject to regulation, and questions for SERs. We met with 
SERs that will be impacted directly by this proposed rule to discuss 
the outreach materials and receive feedback on the approaches and 
alternatives detailed in the outreach packet. The Panel received 
written comments from the SERs following the meeting in response to 
discussions at the meeting and the questions posed to the SERs by the 
Agency. The SERs were specifically asked to provide comment on 
regulatory alternatives that could help to minimize the rule's impact 
on small businesses. (See elsewhere in this preamble for further 
information regarding the SBAR process.)
    EPA consulted with state and local officials in the process of 
developing the proposed action to permit them to have meaningful and 
timely input into its development. EPA met with 10 national 
organizations representing state and local elected officials to provide 
general background on the proposal, answer questions, and solicit input 
from state/local governments. EPA also consulted with tribal officials 
early in the process of developing this proposed rule to permit them to 
have meaningful and timely input into its development. Consultation 
letters were sent to 584 tribal leaders. The letters provided 
information regarding EPA's development of NESHAP for EGUs and offered 
consultation. Three consultation meetings were requested and held. The 
Unfunded Mandates Reform Act (UMRA) discussion in this preamble 
includes a description of the consultation. (See elsewhere in this 
preamble for further information regarding these consultations with 
state, local, and tribal officials.)

XII. 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, EPA submitted this action to the OMB for review under 
EO 12866 and any changes in response to OMB recommendations have been 
documented in the docket for this action. For more information on the 
costs and benefits for this rule, please refer to Table 28 of this 
preamble.
    When estimating the human health benefits and compliance costs in 
Table 28 of this preamble, EPA applied methods and assumptions 
consistent with the state-of-the-science for human health impact 
assessment, economics and air quality analysis. 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

[[Page 25079]]

basis for EPA's assumptions and characterizes the various sources of 
uncertainties affecting the estimates below. In doing what is laid out 
above in this paragraph, 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 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 section 316(b) of the CWA. They will also 
soon be the subject of a rulemaking under CAA section 111 concerning 
emissions of GHG. In developing today's proposed rule, EPA recognizes 
that it needs to endeavor to approach these rulemakings in ways that 
allow the industry to make practical investment decisions that minimize 
costs in complying with all of the final rules, while still achieving 
the fundamentally important environmental and public health benefits 
that underlie the rulemakings.
1. Human Health and Environmental Effects Due to Exposure to MeHg
    In this section, we provide a qualitative description of human 
health and environmental effects due to exposure to MeHg. In 2000, the 
NAS Study was issued which provides a thorough review of the effects of 
MeHg on human health (NRC, 2000). Many of the peer-reviewed articles 
cited in this section are publications originally cited in the MeHg 
Study. In addition, EPA has conducted literature searches to obtain 
other related and more recent publications to complement the material 
summarized by the NRC in 2000.
2. Reference and Benchmark Doses
    In 1995, EPA set a health-based ingestion rate for chronic oral 
exposure to MeHg, termed an oral RfD, at 0.0001 mg/kg-day. The RfD was 
based on effects reported to children exposed in utero during the Iraqi 
poisoning episode (Marsh, et al., 1987). Subsequent research from large 
epidemiological studies in the Seychelles, Faroe Islands, and New 
Zealand added substantially to the body of knowledge on neurological 
effects from MeHg exposure. Per Congressional direction via the House 
Appropriations Report for Fiscal Year 1999, the NRC was contracted by 
EPA to examine these data and, if appropriate, make recommendations for 
deriving a revised RfD. The NRC's analysis concluded that the Iraqi 
study on children exposed in utero should no longer be considered the 
critical study for the derivation of the RfD. NRC also provided 
specific recommendations to EPA for a MeHg RfD based on analyses of the 
three large epidemiological studies (NRC, 2000). Although derived from 
a more complete data set and with a somewhat different methodology, the 
current RfD is numerically the same as the previous (1995) RfD (0.0001 
mg/kg-day).
    The RfD is an estimate (with uncertainty spanning perhaps an order 
of magnitude) of a daily exposure to the human population (including 
sensitive subgroups) that is likely to be without an appreciable risk 
of deleterious effects during a lifetime (EPA, 2002). Data published 
since 2001, development of risk assessment methods, and continued 
examination of the concepts underlying benchmark doses and RfDs based 
on them add to EPA's interpretation of the 2001 MeHg RfD in the current 
rulemaking. Additional information on EPA's interpretation can be found 
in Section X of the Appropriate & Necessary TSD.
3. Neurologic Effects of Exposure to MeHg
    In their review of the literature, the NRC found neurodevelopmental 
effects to be the most sensitive endpoints and appropriate for 
establishing an RfD (NRC, 2000). Studies involving animals found 
sensory effects and support the conclusions reached by studies 
involving human subjects, with a similar range of neurodevelopmental 
effects reported (NRC, 2000). As noted by the NRC, the clinical 
significance of some of the more subtle endpoints included in the human 
low-dose studies is difficult to gauge due to the quantal nature of the 
effects observed (i.e., subjects either display the abnormality or do 
not) and the rather low occurrence rate of these effects.
    Little is known about the effects of low-level chronic MeHg 
exposure in children that can be linked to exposures after birth. The 
difficulty in identifying a cohort exposed after birth but not 
prenatally, or separating prenatal from postnatal effects, makes 
research on the topic complicated. These challenges were present in the 
three large epidemiologic studies used to derive the RfD, as in all 
three studies there was postnatal exposure as well.
    Several studies have shown neurological effects including delayed 
peak latencies in brainstem auditory evoked potentials are associated 
with prenatal or recent MeHg exposures (Debes, et al., 2006; Grandjean, 
et al., 1997; Murata, et al., 2004). A recent case control study of 
Chinese children in Hong Kong (Cheuk and Wong, 2006) paired 59 normal 
controls with 52 children (younger than 18 years) diagnosed with 
attention deficit/hyperactivity disorder (ADHD). The authors reported a 
significant difference in blood Hg levels between cases and controls 
(geometric mean 18.2 nmol/L (95 percent confidence interval, CI, 15.4-
21.5 nmol/L] vs. 11.6 nmol/L [95 percent CI 9.9-13.7 nmol/L], p < 
0.001), which persisted after they adjusted for age, gender and 
parental occupational status (p less than 0.001).
    Several studies have also examined the effects of chronic low-dose 
MeHg exposures on adult neurological and sensory functions (e.g., 
Lebel, et al., 1996; Lebel, et al., 1998; Beuter and Edwards, 1998). 
Research results suggest that elevated hair MeHg concentrations in 
individuals are associated with visual deficits, including loss of 
peripheral vision and chromatic and contrast sensitivity. These 
concentrations range between a high of 50 ppm, and possibly as low as 
20 ppm, although a no observed adverse effect level (NOAEL) was not 
clearly estimated). These individuals also exhibited a loss of manual 
dexterity, hand-eye coordination, and grip strength; difficulty 
performing complex sequences of movement; and (at the higher doses) 
tremors, although expression of some effects was sex-specific. Although 
additional data would be needed to quantify a dose-response 
relationship for these effects, it is noteworthy that the effects 
occurred at doses lower than the Japanese and Iranian poisoning 
episodes, via consumption of Hg-laden fish in riverine Brazilian 
communities. These are areas where extensive Hg contamination has 
resulted from small-scale gold mining activities begun in the 1980s. 
Note that these doses are above the EPA's RfD equivalent level for hair 
Hg. In regard to the Lebel, et al. (1998) study, the NRC states that 
``the mercury exposure of the cohort is presumed to have resulted from 
fish-consumption

[[Page 25080]]

patterns that are stable and thus relevant to estimating the risk 
associated with chronic, low-dose MeHg exposure'' (NRC, 2000). The NRC 
noted, however, ``that the possibility cannot be excluded that the 
neurobehavioral deficits of the adult subjects were due to increased 
prenatal, rather than ongoing, MeHg exposure.'' More recent studies in 
the Brazilian communities provide some evidence that the adverse 
neurobehavioral effects may in fact result from postnatal exposures 
(e.g., Yokoo, et al., 2003); however, additional longitudinal study of 
these and other populations is required to resolve questions regarding 
exposure timing and fully characterize the potential neurological 
impacts of MeHg exposure in adults.
4. Cardiovascular Impacts of Exposure to MeHg
    A number of epidemiological and toxicological studies have 
evaluated the relationship between MeHg exposures and various 
cardiovascular effects including acute myocardial infarction (AMI), 
oxidative stress, atherosclerosis, decreased heart rate variability 
(HRV), and hypertension. An AMI (i.e., heart attack) is clearly an 
adverse health effect. The other four effects are considered 
``intermediary'' effects and risk factors for development of AMI or 
coronary heart disease. Hypertension is a commonly measured clinical 
outcome that is also considered a risk factor for other adverse effects 
(such as stroke).
    These epidemiological studies evaluated Hg exposures using various 
measures (including Hg or MeHg in blood, cord blood, hair and toenails) 
and the associations of these exposures with various effects. The 
overall results of the available studies (published before and after 
NRC 2000) are summarized in the following paragraphs.
    Studies in two cohorts (the Kuopio Ischemic Heart Disease Risk 
Factor study, or KIHD study; and the European Community Multicenter 
Study on Antioxidants, Myocardial Infarction and Breast Cancer, or 
EURAMIC study), report statistically significant positive associations 
between MeHg exposure and AMI. A third study (U.S. Health Professionals 
Study, USHPS) also reported a positive association between Hg exposure 
and AMI but only after excluding individuals who may have been 
occupationally exposed to inorganic Hg. However, a fourth study (the 
Northern Sweden Health and Disease Study, or NSHDS) reported an inverse 
relationship between MeHg exposure and AMI, and another study (Minamata 
Cohort) identified no increase in fatal heart attacks following a MeHg 
poisoning epidemic.
    Although each of these AMI studies had strengths and limitations, 
the EURAMIC and KIHD studies appear to be most robust. Strengths of 
these two studies include their large sample sizes and control for key 
potential confounders (such as exposure to omega-3 fatty acid, which 
are related to decreases in cardiovascular effects). The KIHD study was 
well-designed and included a population-based recruitment and limited 
loss to follow-up. Additional strengths of the EURAMIC study include 
exposure data that were collected shortly after the AMI. In addition, 
recruitment of participants across nine countries likely resulted in a 
wide range of MeHg and fish fatty acid intakes. Although the USHPS 
study was well-conducted, the Hg exposure measure used was potentially 
confounded by possible inorganic Hg exposures in roughly half of the 
study population. When these subjects were excluded from the analyses, 
the power of the study to detect an effect was reduced. Limitations of 
the NSHDS study included its relatively small sample size and narrow 
MeHg exposure range. The Minamata study also had important limitations, 
primarily that the effects of the very high exposures in this 
population may differ substantially from effects of lower exposures 
expected at typical environmental levels; also the death certificates 
were collected starting 10 years after the initial cases of MeHg 
poisoning.
    In summary, the most robust available studies (i.e., the EURAMIC 
and KIHD), report statistically significant positive relationships 
between MeHg exposure and the incidence of AMI. Further, both studies 
report statistically significantly positive trend tests for the 
relationship between MeHg and AMI. The USHPS provides some additional 
evidence of a positive association. The NSHDS and the Minamata Cohort 
studies are less robust; however, the results from those two studies 
showed no adverse effect, and, therefore, reduce the overall confidence 
in the association of MeHg with AMIs.
    The studies that evaluated intermediary effects generally provide 
some additional evidence of the potential adverse effects of Hg or MeHg 
to the cardiovascular system. However, results are somewhat 
inconsistent. For example, two epidemiological studies (the KIHD and 
the Tapaj[oacute]s River Basin studies) reported positive associations 
between MeHg exposures and oxidative stress, but one short-term study 
(the Quebec Sport Fisherman Study) reported a negative association. For 
atherosclerosis, the results across epidemiological studies are more 
consistent. Three studies (the KIHD, Faroese Whaler Cohort Study, and 
Nunavik Inuit Cohort in Quebec) reported a positive association between 
MeHg exposure and atherosclerosis. Moreover, animal studies and in 
vitro studies (cell studies) provide additional evidence that MeHg may 
cause oxidative stress and increased risk of atherosclerosis.
    Another intermediary effect, decreases in heart rate variability 
(HRV), can be indicative of cardiovascular disease, particularly in the 
elderly. Associations of decreased HRV with increased MeHg exposures 
have been reported in four of five studies of adults and three studies 
of children; however, the clinical significance of decreased HRV in 
children is not known.
    The existing epidemiological studies are inconsistent in showing an 
association between MeHg and hypertension. A prospective study of the 
Faroe Islands birth cohort reported statistically significant 
associations between elevated cord blood Hg levels or maternal hair Hg 
levels and increased diastolic and systolic blood pressures for 7-year-
old children; this association was no longer seen in the children 
tested at 14 years. Other studies suggest that these are not 
correlated.
    In January 2010, EPA sponsored a workshop in which a group of 
experts were asked to assess the plausibility of a causal relationship 
between MeHg exposure and cardiovascular health effects, and to advise 
EPA on methodologies for estimating population-level cardiovascular 
health impacts of reduced MeHg exposure. The final workshop report was 
published in January, 2011, and includes as its key recommendation the 
development of a dose-response function relating MeHg exposure and AMI 
incidence for use in regulatory benefits analyses that target Hg air 
emissions.
    The experts identified both intermediary and clinical effects in 
the published literature. The panelists assessed the strength of 
evidence associated with three intermediary effects (i.e., oxidative 
stress, atherosclerosis, and HRV), and with two main clinical effects 
(i.e., hypertension and AMI). The panel concluded there was at least 
moderate evidence of an association between MeHg exposure and all of 
these effects in the epidemiological literature. The evidence for an 
association with hypertension was considered the weakest.
    The workshop panel concluded that ``a causal link between MeHg and 
AMI

[[Page 25081]]

is plausible, given the range of intermediary effects for which some 
positive evidence exists and the strength and consistency across the 
epidemiological studies for AMI.'' During the workshop, the individual 
experts provided quantitative estimates of the likelihood of a true 
causal relationship between MeHg and AMI, ranging from 0.45 to 0.80, 
and characterized by the panel as ``moderate to strong.'' A recently 
published health benefits analysis of reduced MeHg exposures analyzed 
the epidemiology literature and assessed the ``plausibility of causal 
interpretation of cardiovascular risk'' as about \1/3\ as a separate 
parameter in their analysis.
    EPA did not develop a quantitative dose-response assessment or 
quantified estimates of benefits 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.
5. 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 NRC concluded that evidence that human exposure to MeHg 
caused genetic damage is inconclusive; they note that some earlier 
studies showing chromosomal damage in lymphocytes may not have 
controlled sufficiently for potential confounders.) One study of adults 
living in the Tapaj[oacute]s River region in Brazil (Amorim, et al., 
2000) reported a direct relationship between MeHg concentration in hair 
and DNA damage in lymphocytes,; polyploidal aberrations and chromatid 
breaks observed at Hg hair levels around 7.25 ppm and 10 ppm, 
respectively. Long-term MeHg exposures in this population were believed 
to occur through consumption of fish, suggesting that genotoxic effects 
(largely chromosomal aberrations) may result from dietary, chronic MeHg 
exposures similar to and above those seen in the Faroes and Seychelles 
populations.
6. 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). Some persistent 
immunotoxic effects have been observed in mice treated with MeHg in 
drinking water at relatively high levels of exposure (Havarinasab, et 
al., 2007). A recent study of fish-consuming communities in Amazonian 
Brazil has identified a possible association between MeHg exposure and 
immunotoxic effects reflective of autoimmune dysfunction. The authors 
noted that this may reflect interactions with infectious disease and 
other factors (Silva, et al., 2004). Exposures to these communities 
occurred via fish consumption (some community members were also exposed 
to inorganic Hg through gold mining activities). The researchers 
assessed levels of specific antibodies that are markers of Hg-induced 
autoimmunity. They found that both prevalence and levels of these 
antibodies were higher in a population exposed to MeHg via fish 
consumption compared to a reference (unexposed) population. Median hair 
Hg concentration was 8 ppm in the more exposed population (range 0.29 
to 58.47 ppm) and 5.57 ppm in the less exposed reference population 
(range 1.19 to 16.96 ppm). The ranges of Hg hair concentrations 
reported in this study are within an order of magnitude of the 
concentration corresponding to the MeHg RfD. Overall, there is a 
relatively small body of evidence from human studies that suggests 
exposure to MeHg can result in immunotoxic effects.
7. Other Hg-Related Human Toxicity Data
    Based on limited human and animal data, MeHg is classified as a 
``possible'' human carcinogen by the IARC (1994) and in the IRIS (EPA, 
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; NRC, 
2000). The Mercury Study observed that ``MeHg is not likely to be a 
human carcinogen under conditions of exposure generally encountered in 
the environment'' (p 6-16, Vol. V). This was based on observation that 
tumors were noted in one species only at doses causing severe toxicity 
to the target organ. Although some of the human and animal research 
suggests that a link between MeHg and cancer may plausibly exist, more 
research is needed.
    There is also some evidence of reproductive and renal toxicity in 
humans from MeHg exposure. For example, a smaller than expected number 
of pregnancies were observed among women exposed via contaminated wheat 
in the Iraqi poisoning episode of 1956 (Bakir, et al., 1973); other 
victims of that same poisoning event exhibited signs of renal damage 
(Jalili and Abbasi, 1961); and an increased incidence of deaths due to 
kidney disease was observed in women exposed in Minamata Bay via 
contaminated fish (Tamashiro, et al., 1986). Other data from animal 
studies suggest a link between MeHg exposure and similar reproductive 
and renal effects, as well as hematological toxicity (NRC, 2000). 
Overall, human data regarding reproductive, renal, and hematological 
toxicity from MeHg are very limited and are based on either studies of 
the two high-dose poisoning episodes in Iraq and Japan or animal data, 
rather than epidemiological studies of chronic exposures at the levels 
of interest in this analysis. Note that the Mercury Study provides an 
assessment of MeHg cancer risk using the 1993 version of the Revised 
Cancer Guidelines.
8. 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. In the sections that follow, numerous adverse 
effects have been identified. Further reducing the presence of Hg in 
the environment may help to alleviate the potential for adverse 
ecological health outcomes.
    A review of the literature on effects of Hg on fish \188\ reports 
results for numerous species including trout, bass (large and 
smallmouth), northern pike, carp, walleye, salmon, and others from

[[Page 25082]]

laboratory and field studies. The studies were conducted in areas from 
New York to Washington and the effects studied 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. Lower fish 
populations would conceivably impact the ecosystem services like 
recreational fishing derived from having healthy aquatic ecosystems.
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    \188\ Crump, KL, and Trudeau, VL. Mercury-induced reproductive 
impairment in fish. Environmental Toxicology and Chemistry. Vol. 28, 
No. 5, 2009.
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    Mercury also affects avian species. In previous reports \189\ much 
of the focus has been on large piscivorous species in particular the 
common loon. The loon is most visible to the public during the summer 
breeding season on northern lakes and they have become an important 
symbol of wilderness in these areas.\190\ A multitude of loon watch, 
preservation, and protection groups have formed over the past few 
decades and have been instrumental in promoting conservation, 
education, monitoring, and research of breeding loons.\191\ Significant 
adverse effects on breeding loons from Hg have been found to occur 
including behavioral (reduced nest-sitting), physiological (flight 
feather asymmetry) and reproductive (chicks fledged/territorial pair) 
effects and reduced survival.\192\ Additionally, Evers, et al. (see 
footnote 5), report that they believe that the weight of evidence 
indicates that population-level effects occur in parts of Maine and New 
Hampshire, and potentially in broad areas of the loon's range.
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    \189\ 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. Office of Air Quality 
Planning and Standards, 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.
    \190\ McIntyre, JW, Barr, JF. 1997. Common Loon (Gavia immer) 
in: Pool A, Gill F (eds) The Birds of North America. Academy of 
Natural Sciences, Philadelphia, PA, 313.
    \191\ McIntrye, JW, and Evers, DC, (eds) 2000. Loons: old 
history and new finding. Proceedings of a Symposium from the 1997 
meeting, American Ornithologists' Union. North American Loon Fund, 
15 August 1997, Holderness, NH, USA; Evers, DC, 2006. Status 
assessment and conservation plan for the common loon (Gavia immer) 
in North America. U.S. Fish and Wildlife Service, Hadley, MA, USA.
    \192\ 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.
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    Recently attention has turned to other piscivorous species such as 
the white ibis, and great snowy egret. Although considered to be fish-
eating generally, these wading birds have a very wide diet including 
crayfish, crabs, snails, insects and frogs. These species are 
experiencing a range of adverse effects due to exposure to Hg. The 
white ibis has been observed to have decreased foraging 
efficiency.\193\ Additionally ibises have been shown to exhibit 
decreased reproductive success and altered pair behavior.\194\ These 
effects include significantly more unproductive nests, male/male 
pairing, reduced courtship behavior and lower nestling production by 
exposed males. In this study, a worst-case scenario suggested by the 
results could involve up to a 50 percent reduction in fledglings due to 
MeHg in diet. In egrets, Hg has been implicated in the decline of the 
species in south Florida \195\ and Hoffman \196\ has shown that egrets 
show liver and possibly kidney effects. Although ibises and egrets are 
most abundant in coastal areas and these studies were conducted in 
south Florida and Nevada the ranges of ibises and egrets extend to a 
large portion of the U.S.
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    \193\ 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.
    \194\ 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.
    \195\ 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.
    \196\ 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. These songbirds such as Bicknell's thrush, tree 
swallows, and the great tit have shown reduced reproduction, survival, 
and changes in singing behavior. Exposed tree swallows produced fewer 
fledglings,\197\ lower survival,\198\ and had compromised immune 
competence.\199\ The great tit has exhibited reduced singing behavior 
and smaller song repertoire in areas of high contamination.\200\ These 
effects may result in population reductions sufficient to affect 
people's enjoyment of these birds.
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    \197\ Brasso, RL, and Cristol, DA. Effects of mercury exposure 
in the reproductive success of tree swallows (Tachycineta bicolor). 
Ecotoxicology. 17:133-141, 2008.
    \198\ 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.
    \199\ Hawley, DM, Hallinger, KK, Cristol, DA. Compromised immune 
competence in free-living tree swallows exposed to mercury. 
Ecotoxicology. 18:499-503, 2009.
    \200\ 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 on Hg in fur nearly equal or exceed a 
concentration associated with mortality and concentration in liver for 
mink in Massachusetts/Connecticut and the levels in fur from mink in 
Maine exceed concentrations associated with acute mortality.\201\ 
Adverse sublethal effects may be associated with lower Hg 
concentrations and consequently be more widespread than potential acute 
effects. These effects may include increased activity, poorer maze 
performance, abnormal startle reflex, and impaired escape and avoidance 
behavior.\202\ Although we do not have data to show population level 
effects that would impact wildlife viewing and enjoyment these are 
ecosystem services potentially affected by impacts on these species.
---------------------------------------------------------------------------

    \201\ 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.
    \202\ 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.
---------------------------------------------------------------------------

    The proposed rule will also reduce emissions of directly emitted PM 
and ozone precursors and estimates of the PM2.5-related co-
benefits of these air quality improvements may be found in Table 28 of 
this preamble. When characterizing uncertainty in the PM-mortality 
relationship, 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, 
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

[[Page 25083]]

out impacts predicted to be associated levels above and below a 
``bright line'' threshold, EPA includes a ``lowest measured level'' 
(LML) analysis that illustrates the increasing uncertainty that 
characterizes exposure attributed to levels of PM2.5 below 
the LML of each epidemiological study used to estimate 
PM2.5-related premature death. Figures provided in the RIA 
show the distribution of baseline exposure to PM2.5, as well 
as the lowest air quality levels measured in each of the epidemiology 
cohort studies. This information provides a context for considering the 
likely portion of PM-related mortality benefits occurring above or 
below the LML of each study; in general, our confidence in the size of 
the estimated reduction PM2.5-related premature mortality 
diminishes as baseline concentrations of PM2.5 are lowered. 
Using the Pope, et al. (2002) study, 86 percent of the population is 
exposed at or above the LML of 7.5 [mu]g/m\3\. Using the Laden, et al. 
(2006) study, 30 percent of the population is exposed at or above the 
LML of 10 [mu]g/m\3\. Although the LML analysis provides some insight 
into the level of uncertainty in the estimated PM mortality benefits, 
EPA does not view the LML as a threshold and continues to quantify PM-
related mortality impacts using a full range of modeled air quality 
concentrations. It is important to note that the monetized benefits 
include many but not all health effects associated with 
PM2.5 exposure. Benefits are shown as a range from Pope, et 
al., (2002) to Laden, et al., (2006). These models assume that all fine 
particles, regardless of their chemical composition, are equally potent 
in causing premature mortality because there is no clear scientific 
evidence that would support the development of differential effects 
estimates by particle type.
    The cost analysis is also subject to uncertainties. Estimating the 
cost conversion from one process to another is more difficult than 
estimating the cost of adding control equipment because it is more 
dependent on plant specific information. More information on the cost 
uncertainties can be found in the RIA.
    A summary of the monetized benefits and net benefits for the 
proposed rule at discount rates of 3 percent and 7 percent is in Table 
28 of this preamble.
    For more information on the benefits 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 proposed rule will 
be submitted for approval to the OMB under the PRA, 44 U.S.C. 3501 et 
seq. An ICR document has been prepared by EPA (ICR No. 2137.05).
    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 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 proposed rule would require maintenance inspections of the 
control devices but would not require any notifications or reports 
beyond those required by the General Provisions. The recordkeeping 
requirements require only the specific information needed to determine 
compliance.
    The annual monitoring, reporting, and recordkeeping burden for this 
collection (averaged over the first 3 years after the effective date of 
the standards) is estimated to be $49.1 million. This includes 329,605 
labor hours per year at a total labor cost of $27.0 million per year, 
and total non-labor capital costs of $22.1 million per year. This 
estimate includes initial and annual performance test, conducting and 
documenting a tune-up, semiannual excess emission reports, maintenance 
inspections, developing a monitoring plan, notifications, and 
recordkeeping. The total burden for the Federal government (averaged 
over the first 3 years after the effective date of the standard) is 
estimated to be 18,039 hours per year at a total labor cost of $877 
million per year.
    Burden means the total time, effort, or financial resources 
expended by persons to generate, maintain, retain, or disclose or 
provide information to or for a Federal agency. This includes the time 
needed to review instructions; develop, acquire, install, and utilize 
technology and systems for the purposes of collecting, validating, and 
verifying information, processing and maintaining information, and 
disclosing and providing information; adjust the existing ways to 
comply with any previously applicable instructions and requirements; 
train personnel to be able to respond to a collection of information; 
search data sources; complete and review the collection of information; 
and transmit or otherwise disclose the information.
    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 and 48 CFR chapter 15.
    To comment on EPA's need for this information, the accuracy of the 
provided burden estimates, and any suggested methods for minimizing 
respondent burden, including the use of automated collection 
techniques, EPA has established a public docket for this proposed rule, 
which includes this ICR, under Docket ID number EPA-HQ-OAR-2009-0234. 
Submit any comments related to the ICR to EPA and OMB. See ADDRESSES 
section at the beginning of this preamble for where to submit comments 
to EPA. Send comments to OMB at the Office of Information and 
Regulatory Affairs, Office of Management and Budget, 725 17th Street, 
NW., Washington, DC 20503, Attention: Desk Office for EPA. Because OMB 
is required to make a decision concerning the ICR between 30 and 60 
days after May 3, 2011, a comment to OMB is best assured of having its 
full effect if OMB receives it by June 2, 2011. The final rule will 
respond to any OMB or public comments on the information collection 
requirements contained in this proposal.

C. Regulatory Flexibility Act (RFA), as Amended by the Small Business 
Regulatory Enforcement Fairness Act of 1996 (SBREFA), 5 U.S.C. 601 et 
seq.

    The 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 proposed rule on 
small entities, small entity is defined as (as defined by the Small 
Business Administration's (SBA) regulations at 13 CFR 121.201): (1) A 
small business according to SBA size standards by the North American 
Industry Classification System category of the owning entity (for NAICS 
221112 and 221122, the range of small business size standards for 
electric utilities is 4 million

[[Page 25084]]

megawatt hours of production or less); (2) a small governmental 
jurisdiction that is a government of a city, county, town, township, 
village, 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.
    After considering the economic impacts of this proposed rule on 
small entities, EPA cannot certify that this action will not have a 
significant economic impact on a substantial number of small entities. 
This determination, which is included in the Initial Regulatory 
Flexibility Analysis (IRFA) found in Chapter 10 of the RIA for this 
proposed rule, is based on the economic impact of this proposed rule to 
all affected small entities across the electric power sector.
    The summary of the IRFA is as follows. EPA has assessed the 
potential impact of this action on small entities and found that 
approximately 102 of the estimated 1,400 EGUs potentially affected by 
today's proposed rule are owned by the 83 potentially affected small 
entities identified by EPA's analysis. EPA estimates that 59 of the 83 
identified small entities will have annualized costs greater than 1 
percent of their revenues.
    Because the potential existed for a likely significant impact for 
substantial number of small entities, 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 this 
rule.
1. Panel Process and Panel Outreach
    As required by RFA section 609(b), as amended by SBREFA, EPA has 
conducted outreach to small entities and on October 27, 2010, EPA's 
Small Business Advocacy Chairperson convened a Panel under RFA section 
609(b). In addition to the Chair, the Panel consisted of the Director 
of the Sector Policies and Programs Division within EPA's Office of Air 
and Radiation, the Chief Counsel for Advocacy of SBA, and the 
Administrator of the Office of Information and Regulatory Affairs 
within OMB.
    As part of the SBAR Panel process we conducted outreach with 
representatives from 18 various small entities that potentially would 
be affected by this rule. The SERs included representatives of EGUs 
owned by municipalities, cooperatives, and private investors. We 
distributed outreach materials to the SERs; these materials included 
background and project history, CAA section 112 overview, constraints 
on the rulemaking, rulemaking options under consideration, and 
potential control technologies and estimated cost. We met with 14 of 
the SERs, as well as five non-SER participants from organizations 
representing power producers, on December 2, 2010, to discuss the 
outreach materials, potential requirements of the rule, and regulatory 
areas where EPA has discretion and could potentially provide 
flexibility. The Panel received written comments from, or on behalf of, 
10 SERs following the meeting in response to discussions at the meeting 
and the questions posed to the SERs by the Agency. The SERs were 
specifically asked to provide comment on regulatory approaches that 
could help to minimize the rule's impact on small businesses.
2. Panel Recommendations for Small Business Flexibilities
    Consistent with the RFA/SBREFA requirements, the Panel evaluated 
the assembled materials and small-entity comments on issues related to 
elements of the IRFA. A copy of the Final Panel Report (including all 
comments received from SERs in response to the Panel's outreach 
meeting) is included in the docket for this proposed rule. In general, 
the Panel recommended that EPA consider its various flexibilities to 
the maximum extent possible consistent with CAA requirements to 
mitigate the impacts of the rulemaking on small businesses and to seek 
comment on potential adverse economic impacts of the proposed rule on 
affected small entities and recommendations to mitigate such impacts. 
With respect to specific issues and options, however, there were 
varying recommendations from panel members. Issues and options 
discussed among the panel members included: (1) MACT floor 
determinations and variability assessment; (2) monitoring, reporting, 
and recordkeeping requirements; (3) subcategorization; (4) area source 
standards; (5) work practice standards; (6) health based emission 
limits; (7) related Federal rules; (8) potential adverse economic 
impacts; and (9) concerns with the SBAR process. Panel member 
recommendations regarding each of these issues and options are 
presented in Chapter 9 of the Final Panel Report. As noted elsewhere in 
this preamble, this proposal is based on a regulatory alternative that 
includes subcategorization, MACT floor-based numerical emission 
limitations, work practice standards, alternative standards, 
alternative compliance options, and emissions averaging.
    We invite comments on all aspects of the proposal and its impacts, 
including potential adverse impacts, on small entities.

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 proposed 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 for the Proposed 
Toxics Rule'' under UMRA section 202 that is within the RIA and which 
is summarized below.

[[Page 25085]]

1. Statutory Authority
    As discussed elsewhere in this preamble, the statutory authority 
for this proposed 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 is presented in the RIA for this rulemaking and in the 
docket. The regulatory alternative upon which this proposed rule is 
based represents the MACT floor for all regulated pollutants for four 
of the five subcategories of EGUs and for all but one regulated 
pollutant for the fifth subcategory. These proposed MACT floor-based 
standards represent the least costly and least burdensome alternative. 
Beyond-the-floor emission limits for Hg are proposed for existing and 
new EGUs designed to burn coal having a calorific value less than 8,300 
Btu/lb.
2. Social Costs and Benefits
    The RIA prepared for this proposed rule including the Agency's 
assessment of costs and benefits and is in the docket.
    It is estimated that 3 years after implementation of this proposed 
rule, HAP would be reduced by thousands of tons, including reductions 
in HCl, HF, metallic HAP (including Hg), and several other organic HAP 
from EGUs. Studies have determined a relationship between exposure to 
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, there are significant reductions in PM2.5 and in 
SO2 that would occur, including approximately 84 thousand 
tons of PM2.5 and over 2 million tons of SO2. 
These reductions 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, 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 
proposed alternative range from $59 billion (2007 dollars) to $140 
billion (2007 dollars) when using a 3 percent discount rate (or from 
$53 billion (2007 dollars) to $130 billion (2007 dollars) when using a 
7 percent discount rate). Our estimate of social costs is $10.9 billion 
(2007 dollars). For more detailed information on the benefits and costs 
estimated for this proposed rulemaking, refer to the RIA in the docket.
3. Future and Disproportionate Costs
    UMRA requires that we estimate, where accurate estimation is 
reasonably feasible, future compliance costs imposed by this proposed 
rule and any disproportionate budgetary effects. Our estimates of the 
future compliance costs of this proposed rule are discussed previously 
in this preamble.
    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. EPA projects that 55 government entities 
will have compliance costs greater than 1 percent of base generation 
revenue in 2016, and 37 may experience compliance costs greater than 3 
percent of base revenues. Also, one government entity is estimated to 
have all of its affected units retire. Overall, 17 units owned by 
government entities retire. It is also worth noting that two-thirds of 
the net compliance costs shown above are due to lost profits from 
retirements. More than half of those lost profits arise from retiring 
two large units, according to EPA modeling. For more details on these 
results and the methodology behind their estimation, see the results 
included in the RIA and which are discussed previously in this 
preamble.
4. Effects on the National Economy
    UMRA requires that we estimate the effect of this proposed 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 proposed rule is presented 
in the RIA in the docket. This analysis provides estimates of the 
effect of this proposed 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 there will be a less than 4 
percent increase in electricity price on average nationwide in 2016, 
and a less than 7 percent increase in natural gas price nationwide in 
2016. Power generation from coal-fired plants will fall by about 1 
percent nationwide in 2016.
5. Consultation With Government
    UMRA requires that we describe the extent of the Agency's prior 
consultation with affected State, local, 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 
proposal. Consistent with the intergovernmental consultation provisions 
of UMRA section 204, EPA has initiated consultations with governmental 
entities affected by this proposed rule. 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 EPA as the 
``Big 10'' organizations appropriate to contact for purpose of 
consultation with elected officials. The purposes of the consultation 
were to

[[Page 25086]]

provide general background on the proposal, 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 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 EPA provided, addresses 
associated with the 112 state and local governments estimated to be 
potentially impacted by the proposed rule. EPA has not received 
additional questions or requests from state or local officials.
    Consistent with UMRA section 205, EPA has identified and considered 
a reasonable number of regulatory alternatives. Because the potential 
existed for a likely significant impact for substantial number of small 
entities, 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, EPA 
considered several options. 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 proposed provisions regarding a number of the recommendations 
resulting from the SBAR Panel process as described below (see elsewhere 
in this preamble for more detail).
    EPA determined that there is a distinguishable difference in 
emissions characteristics associated with five EGU design types and 
that these characteristics may affect the feasibility and/or 
effectiveness of emission control. Thus, the five types of units are 
proposed to be regulated separately (i.e., subcategorized) to account 
for the difference in emissions and applicable controls. The proposal 
establishes three subcategories for coal-fired EGUs and two 
subcategories for oil-fired EGUs: (1) Coal-fired units designed to burn 
coal having a calorific value of 8,300 Btu/lb or greater, (2) coal-
fired units designed to burn virgin coal having a calorific value less 
than 8,300 Btu/lb, (3) IGCC units (for Hg emissions only), (4) liquid 
oil units, and (5) solid oil-derived units.
    The regulatory alternative upon which the proposed standards for 
coal-fired EGUs are based includes: (1) MACT floor-based numerical 
emission limitations for HCl (a HAP as well as a surrogate for all 
other acid gas HAP) and for PM (a surrogate for non-Hg metallic HAP) 
for existing and new EGUs in all three subcategories; (2) MACT floor-
based numerical emission limitations for Hg for existing and new coal-
fired units designed to burn coal having a calorific value of 8,300 
Btu/lb or greater and IGCC units; (3) beyond-the-floor numerical 
emission limitations for Hg for existing and new coal-fired units 
designed to burn virgin coal having a calorific value less than 8,300 
Btu/lb; and (4) work practices to limit emissions of dioxin/furan 
organic HAP and non-dioxin/furan organic HAP for existing and new EGUs 
in all three subcategories. The regulatory alternative upon which the 
proposed standards for oil-fired EGUs are based includes: (1) MACT 
floor-based numerical emission limitations for Hg, total non-Hg 
metallic HAP, HCl, and HF for existing and new EGUs in both 
subcategories; and (2) work practices to limit emissions of dioxin/
furan organic HAP and non-dioxin/furan organic HAP for existing and new 
EGUs in both subcategories. The proposed use of surrogate pollutants 
would result in reduced compliance costs because testing would only be 
required for the surrogate pollutants (i.e., HCl and PM) versus for the 
HAP (i.e., acid gases and non-Hg metals).
    EPA also is proposing three alternative standards for certain 
subcategories: (1) SO2 (as an alternate to HCl for all 
subcategories with add-on FGD systems except IGCC units and liquid oil-
fired units); (2) individual non-Hg metallic HAP (as an alternate to PM 
for all subcategories except liquid oil-fired units, and as an 
alternative to total non-Hg metallic HAP for the liquid oil-fired units 
subcategory); and (3) total non-Hg metallic HAP (as an alternate to PM 
for all subcategories except liquid oil-fired units). In addition, 
liquid oil-fired EGUs may choose to demonstrate compliance with the Hg, 
non-Hg metallic HAP, HCl, and HF emission limits on the basis of fuel 
analysis. Maximum fuel inlet values for Hg, non-Hg metals, chlorine, 
and fluorine would be established based on the inlet fuel values 
measured during the performance test indicating compliance with the 
emission limits. We also are proposing that owners and operators of 
existing affected sources may demonstrate compliance by emissions 
averaging for units at the affected source that are within a single 
subcategory. Alternative standards, alternative compliance options, and 
emissions averaging can provide sources the flexibility to comply in 
the least costly manner.
    The proposed work practice standard, which requires implementation 
of an annual performance (compliance) test program includes 
requirements to inspect the burner, flame pattern, and the system 
controlling the air-to-fuel ratio, and make any necessary adjustments 
and/or conduct any required maintenance and repairs; minimize CO 
emissions consistent with the manufacturer's specifications; measure 
the concentration of CO in the effluent stream before and after any 
adjustments are made; and submit an annual report containing the 
concentrations of CO and O2 measured before and after 
adjustments, a description of any corrective actions taken as a part of 
the combustion adjustment, and the type and amount of fuel used over 
the 12 months prior to the annual adjustment.

E. Executive Order 13132, Federalism

    Under EO 13132, 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 EPA consults with state and local 
officials early in the process of developing the proposed action.
    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, EPA 
provides the following federalism summary impact statement as required 
by section 6(b) of EO 13132.
    Based on the estimates in EPA's RIA for today's proposed rule, the 
proposed regulatory option, if promulgated, may have federalism 
implications because the option may impose approximately $666.3 million 
in annual direct compliance costs on an estimated 97 state or local 
governments. Specifically, we estimate that there are 81 
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

[[Page 25087]]

energy) that may be directly impacted by today's proposed rule. 
Responses to 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.''
    EPA consulted with state and local officials in the process of 
developing the proposed rule to permit them to have meaningful and 
timely input into its development. EPA met with 10 national 
organizations representing state and local elected officials to provide 
general background on the proposal, answer questions, and solicit input 
from state/local governments. The UMRA discussion in this preamble 
includes a description of the consultation.
    In the spirit of EO 13132, and consistent with EPA policy to 
promote communications between EPA and state and local governments, EPA 
specifically solicits comment on this proposed action from state and 
local officials.

F. Executive Order 13175, Consultation and Coordination With Indian 
Tribal Governments

    Subject to EO 13175 (65 FR 67249, November 9, 2000) 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 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 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.''
    EPA has concluded that this action may have tribal implications. 
However, it will neither impose substantial direct compliance costs on 
tribal governments, nor preempt tribal law. This proposed rule would 
impose requirements on owners and operators of EGUs. EPA is aware of 
three coal-fired EGUs located in Indian Country but is not aware of any 
EGUs owned or operated by tribal entities.
    EPA offered consultation with tribal officials early in the process 
of developing this proposed regulation to permit them to have 
meaningful and timely input into its development. Consultation letters 
were sent to 584 tribal leaders. The letters provided information 
regarding EPA's development of NESHAP for EGUs and offered 
consultation. Three consultation meetings were held on December 7, 
2010, with the Upper Sioux Community of Minnesota; on December 13 with 
Moapa Band of Paiutes, Forest County Potawatomi, Standing Rock Sioux 
Tribal Council, Fond du Lac Band of Chippewa; and on January 5, 2011 
with the Forest County Potawatomi, and a representative from the 
National Tribal Air Association (NTAA). In these meetings, EPA 
presented the authority under the CAA used to develop these rules, and 
an overview of the industry and the industrial processes that have the 
potential for regulation. Tribes expressed concerns about the impact of 
EGUs on the reservations. Particularly, they were concerned about 
potential Hg deposition and the impact on the water resources of the 
Tribes, with particular concern about the impact on subsistence 
lifestyles for fishing communities, the cultural impact of impaired 
water quality for ceremonial purposes, and the economic impact on 
tourism. In light of these concerns, the tribes expressed interest in 
an expedited implementation of the rule, they expressed concerns about 
how the Agency would consider variability in setting the standards and 
use 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 they asked the Agency to consider going 
beyond-the-floor to offer more protection for the tribal communities. A 
more specific list of comments can be found in the Docket.
    In addition to these consultations, EPA also conducted outreach on 
this rule through presentations at the National Tribal Forum in 
Milwaukee, WI, and on NTAA calls. EPA specifically requested tribal 
data that could support the appropriate and necessary analysis and the 
RIA for this rule. We will also hold additional meetings with tribal 
environmental staff to inform them of the content of this proposal as 
well as provide additional consultation with tribal elected officials 
where it is appropriate.
    EPA specifically solicits additional comment on this proposed rule 
from tribal officials.

G. Executive Order 13045, Protection of Children From Environmental 
Health Risks and Safety Risks

    Executive Order 13045 (62 FR 19,885, April 23, 1997) applies to any 
rule that: (1) Is determined to be ``economically significant'' as 
defined under EO 12866, and (2) concerns an environmental health or 
safety risk that EPA has reason to believe may have a disproportionate 
effect on children. If the regulatory action meets both criteria, the 
Agency must evaluate the environmental health or safety effects of this 
planned rule on children, and explain why this planned regulation is 
preferable to other potentially effective and reasonably feasible 
alternatives considered by the Agency.
    This proposed rule is subject to EO 13045 because it is an 
economically significant regulatory action as defined by EO 12866, and 
we believe that the action concerns an environmental health risk which 
may have a disproportionate impact on children. Although this proposed 
rule is based on technology performance, the statute is designed to 
require standards that are likely to protect against hazards to public 
health with an adequate margin of safety as described elsewhere in this 
document. The protection offered by this proposed rule is especially 
important for children, especially the developing fetus. As referenced 
in the section entitled, ``Consideration of Health Risks to Children 
and Environmental Justice Communities'' 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 elsewhere in this document.
    The public is invited to submit comments or identify peer-reviewed 
studies and data that assess effects of early life exposure to this 
proposed rule.

H. Executive Order 13211, Actions Concerning Regulations That 
Significantly Affect Energy Supply, Distribution, or Use

    Executive Order 13211, (66 FR 28355, May 22, 2001), provides that 
agencies shall prepare and submit to the Administrator of the Office of 
Information and Regulatory Affairs, OMB, a Statement of Energy Effects 
for certain actions identified as significant energy actions. Section 
4(b) of EO 13211 defines ``significant energy actions'' as ``any action 
by an agency (normally published in the Federal Register) that 
promulgates or is expected to lead to the promulgation of a final rule 
or regulation, including notices of inquiry, advance notices of 
proposed rulemaking, and notices of proposed rulemaking: (1)(i) That is 
a significant regulatory action under EO 12866 or any successor order, 
and (ii) is likely to have a significant adverse effect on the

[[Page 25088]]

supply, distribution, or use of energy; or (2) that is designated by 
the Administrator of the Office of Information and Regulatory Affairs 
as a significant energy action.'' This proposed rule is a ``significant 
regulatory action'' because it may likely have a significant adverse 
effect on the supply, distribution, or use of energy. The basis for the 
determination is as follows.
    We estimate a less than 4 percent price increase for electricity 
nationwide in 2016 and a 1 percent percentage fall in coal-fired power 
production. EPA projects that delivered natural gas prices will 
increase by about 1 percent over the 2015 to 2030 timeframe. For more 
information on the estimated energy effects, please refer to the 
economic impact analysis for this proposed rule. The analysis is 
available in the RIA, which is in the public docket.
    Therefore, we conclude that this proposed rule when implemented is 
likely to have a significant adverse effect on the supply, 
distribution, or use of energy.

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 EPA 
to use voluntary consensus standards (VCS) in their regulatory and 
procurement 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) developed or adopted by one or 
more voluntary consensus bodies. The NTTAA directs EPA to provide 
Congress, through annual reports to OMB, with explanations when an 
agency does not use available and applicable voluntary consensus 
standards.
    This rulemaking involves technical standards. EPA cites the 
following standards in this proposed rule: EPA Methods 1, 2, 2F, 2G, 
3A, 3B, 4, 5, 5D, 6, 6C, 9, 19, 26, 26A, 29, 30A, 30B, and 202 of 40 
CFR part 60. Consistent with the NTTAA, EPA conducted searches to 
identify VCS in addition to these EPA methods. No applicable voluntary 
standards were identified for EPA Methods 2F, 2G, 8, 19, 201A, and 202. 
The search and review results have been documented and are placed in 
the docket for this proposed rule.
    EPA has decided to use American National Standards Institute 
(ANSI)/ASME PTC 19-10-1981 Part 10, ``Flue and Exhaust Gas Analyses,'' 
acceptable as an alternative to Methods 3B (for CO2, CO, and 
O2), 6 (for SO2), 6A and 6B (for CO2 
and SO2). This standard is available from the ASME, Three 
Park Avenue, New York, NY 10016-5990.
    Another VCS, ASTM D6735-01, ``Standard Test Method for Measurement 
of Gaseous Chlorides and Fluorides from Mineral Calcining Exhaust 
Sources Impinger Method,'' is an acceptable alternative to EPA Methods 
26 and 26A.
    An additional VCS, ASTM D6784-02 (2008)--Standard Test Method for 
Elemental, Oxidized, Particle-Bound and Total Mercury Gas Generated 
from Coal-Fired Stationary Sources (Ontario Hydro Method) is acceptable 
as an alternative to Method 29 for Hg, but only if the standard falls 
within the applicable concentration range of 0.5 to 100 [mu]g/Nm\3\.
    During the search, if the title or abstract (if provided) of the 
VCS described technical sampling and analytical procedures that are 
similar to EPA's reference method, EPA ordered a copy of the standard 
and reviewed it as a potential equivalent method. All potential 
standards were reviewed to determine the practicality of the VCS for 
this rule. This review requires significant method validation data 
which meets the requirements of EPA Method 301 for accepting 
alternative methods or scientific, engineering and policy equivalence 
to procedures in EPA reference methods. EPA may reconsider 
determinations of impracticality when additional information is 
available for particular VCS.
    The search identified 22 other VCS that were potentially applicable 
for this rule in lieu of EPA reference methods. After reviewing the 
available standards, EPA determined that 22 candidate VCS (ASTM D3154-
00 (2006), ASME B133.9-1994 (2001), ANSI/ASME PTC 19-10-1981 Part 10, 
ASTM D5835-95 (2007), International Organization for Standards (ISO) 
10396:1993 (2007), ISO 12039:2001, ASTM D6522-00 (2005), Canadian 
Standards Association (CAN/CSA) Z223.2-M86 (1999), ISO 9096:1992 
(2003), ANSI/ASME PTC-38-1980 (1985), ASTM D3685/D3685M-98 (2005), ISO 
7934:1998, ISO 11632:1998, ASTM D3464-96 (2007), ASTM D3796-90 (2004), 
ISO 10780:1994, CAN/CSA Z223.21-M1978, ASTM D3162-94 (2005), CAN/CSA 
Z223.1-M1977, EN 1911-1,2,3 (1998), EN 13211:2001, CAN/CSA Z223.26-
M1987) identified for measuring emissions of pollutants or their 
surrogates subject to emission standards in the proposed rule would not 
be practical due to lack of equivalency, documentation, validation 
data, and other important technical and policy considerations. These 22 
methods are listed Attachment 1 to the documentation memo, along with 
the EPA review comments, which may be found in the docket.

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 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, low-income, and tribal populations in the U.S.
    This proposed rule establishes national emission standards for new 
and existing EGUs that combust coal and oil. EPA estimates that there 
are approximately 1,400 units located at 550 facilities covered by this 
proposed rule.
    This proposed 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 proposed 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; some of the directly-emitted PM 
is in the form of PM2.5. Reducing emissions of PM 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 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 proposed rule will 
also have a small effect on electricity and natural gas

[[Page 25089]]

prices and has the potential to affect the cost structure of the 
utility industry and could lead to shifts in how and where electricity 
is generated. Although energy prices are estimated to increase, we can 
only estimate national impacts. We are unable to determine impacts 
other than at the national level at this time.
    Pursuant to EO 12898 and the ``Interim Guidance on Considering 
Environmental Justice During the Development of an Action'' (July 
2010), during development of a rule EPA considers whether there are 
positive or negative impacts of the action that appear to affect low-
income, minority, or tribal communities disproportionately. Regardless 
of whether a disproportionate effect exists, EPA also considers whether 
there is a chance for these communities to meaningfully participate in 
the rulemaking process.
    Today's proposed rule is one of a group of regulatory actions that 
EPA 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, 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 proposed 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 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 proposed 
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 was 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 EPA's assessment of both the 
underlying risks that make this proposed rule appropriate and 
necessary, and of the analysis of the benefits of reducing exposure to 
Hg and the other hazardous air pollutants.
    EPA's full analysis of risks from consumption of Hg-contaminated 
fish are contained in the preamble for this rule. The effects of this 
proposed rule on the health risks from Hg and other HAP are presented 
in the preamble and in the RIA for this rule. This information can be 
accessed through docket EPA-HQ-OAR-2009-0234 and from the main EPA 
webpage for the rule http://www.epa.gov/ttn/atw/utility/utilitypg.html.
2. Potential Environmental and Public Health Impacts to Vulnerable 
Populations
    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 proposed rule (so-called ``co-benefits'').
    a. Socio-Economic Distribution. As part of the analysis for this 
proposed rule, EPA reviewed the aggregate demographic makeup of the 
communities near EGUs covered by this proposed 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. EGUs 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 Hg and SO2, are known to travel long 
distances and harm both the environment and human health hundreds or 
even thousands of miles from where they were emitted.
    This proximity-to-the-source review is included in the analysis for 
this proposed rule because some EGUs emit enough Ni or Cr to cause 
elevated lifetime cancer risks greater than 1 in a million in nearby 
communities. In addition, EPA's analysis indicates that there are 
localized areas with elevated levels of Hg deposition around most U.S. 
EGUs.
    The review identified those census blocks within two circular 
distances (5 km and 50 km) of coal-fired EGUs and determined their 
demographic and socio-economic composition (e.g., race, income, 
education, etc.). The radius of 5 km (or approximately 3 miles) was 
chosen because it has been used in other demographic analyses focused 
on areas around potential sources. The radius of 50 km (or 
approximately 31 miles) was used to approximate the distance from the 
source where elevated levels of Hg deposition might occur and may also 
be indicative of the area where risks from non-Hg HAP are most likely 
to occur.
    The results of EPA's demographic analysis for coal fired EGUs are 
shown in the following table:

[[Page 25090]]



                  Table 30--Comparative Summary of the Demographics Within 5 KM (3 Miles) and 50 KM (31 Miles) of the Affected Sources
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                              African       Native     Other and                                Below
                                                                White (%)     American     American   multiracial    Hispanic     Minority     poverty
                                                                                (%)          (%)          (%)          (%)          (%)        line (%)
--------------------------------------------------------------------------------------------------------------------------------------------------------
5 km (3-mile) Buffer.........................................         70.8         15.8          0.7         12.7         15.5         35.5         15.6
50 km (31.1 miles) Buffer....................................         74.5         15.2          0.5          9.7          9.9         29.7         11.6
National Average.............................................         75.1         12.3          0.9         11.7         13.7         31.6         13.1
--------------------------------------------------------------------------------------------------------------------------------------------------------

    The data indicate that coal-fired EGUs are located in areas where 
minority share of the population living within a 3-mile buffer is 
higher than the national average. For these same areas, the percent of 
the population below the poverty line is also higher than the national 
average. At 50 km from the source, however, the demographics are 
different. Although the percent African American remain above the 
national average, the percent of minority (including Native Americans) 
and the percent of the population living below the poverty line 
decrease below their respective national averages. 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 take to reduce their emissions of air toxics as 
required by this proposed rule will also reduce emissions of PM and 
SO2. As a result, this proposed 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 work jobs 
that do not provide paid sick days. Many 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 also 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 many 
benefits from reducing it.
    We estimate that in 2016 the PM-related annual benefits of the 
proposed rule for adults include approximately 6600 to 17,000 fewer 
premature mortalities, 4,300 fewer cases of chronic bronchitis, 10,000 
fewer non-fatal heart attacks, 12,000 fewer hospitalizations (for 
respiratory and cardiovascular disease combined), 4.9 million fewer 
days of restricted activity due to respiratory illness and 
approximately 830,000 fewer lost work days. We also estimate 
substantial health improvements for children in the form of 110,000 
fewer asthma attacks, 6,700 fewer hospital admissions due to asthma, 
10,000 fewer cases of acute bronchitis, and approximately 210,000 fewer 
cases of upper and lower respiratory illness.
    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 proposed 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 have substantially higher risks of PM2.5-
related death than people living in the other 95 percent of counties. 
This was true regardless of race; the difference between the groups of 
counties for each race is large while the differences among races in 
both groups of counties is very small. In contrast, the analysis found 
that people with less than high school education have significantly 
greater risks 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 finds that this proposed 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 Appendix C of the RIA.
    EPA estimates that the benefits of the proposed rule are 
distributed among these populations fairly evenly. Therefore, there is 
no indication that people of particular race, income, or level of 
education receive a greater benefit (or smaller benefit) than others. 
However, the analysis does indicate that this proposed rule in 
conjunction with the implementation of existing or proposed rules 
(e.g., the Transport Rule) 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 proposed rule and other rules will, together, 
reduce risks in the highest-risk counties to the approximate level of 
risk for the rest on the counties before implementation.
    These results are presented in more detail in the ``Benefits 
Appendix'' to this rule, a copy of which is available in the docket.
3. Meaningful Public Participation
    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 polices. To promote 
meaningful involvement, EPA has developed a communication and outreach 
strategy to ensure that interested communities have access to

[[Page 25091]]

this proposed rule, are aware of its content, and have an opportunity 
to comment during the comment period. During the comment period, EPA 
will publicize the rulemaking via newsletters, EJ listserves, webinars 
and the internet, including the Office of Policy's (OP) Rulemaking 
Gateway Web site (http://yosemite.epa.gov/opei/RuleGate.nsf/). EPA will 
also provide general rulemaking fact sheets (e.g., why is this 
important for my community) for EJ community groups and conduct 
conference calls with interested communities.
    Once this rule is finalized and implemented, affected EGUs will 
need to update their operating (Title V) permits to reflect their new 
emissions limits and any other applicable requirements (i.e., 
monitoring and recordkeeping) from this rule. The Title V permitting 
process provides that most permit actions must include an opportunity 
for public review and comments. In addition, after the public review 
process, EPA has an opportunity to review the proposed permit and 
object to its issuance if it does not meet CAA requirements. This 
process gives members of affected communities the opportunity to 
comment on the permit conditions for specific sources affected by this 
rulemaking.
4. Summary
    This proposed rule strictly limits the emissions rate of Hg and 
other HAP from every affected EGU in the U.S. EPA's analysis indicates 
substantial health benefits, including for vulnerable populations, from 
reductions in PM2.5. EPA's analysis also indicates 
reductions in risks for individuals, including for members of many 
minority populations, who eat fish frequently from U.S. lakes and 
rivers and who live near affected sources. Based on all the available 
information, EPA has determined that this proposed rule will not have 
disproportionately high and adverse human health or environmental 
effects on minority, low-income, or tribal populations. EPA is 
providing multiple opportunities for EJ communities to both learn about 
and comment on this rule and welcomes their participation.

List of Subjects in 40 CFR Parts 60 and 63

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

    Dated: March 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 proposed to be amended as follows:

PART 60--[AMENDED]

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

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

Subpart A---[Amended]

    2. Section 60.17 is amended:
    a. By redesignating paragraphs (a)(91) and (a)(92) as paragraphs 
(a)(94) and (a)(95);
    b. By redesignating paragraphs (a)(89) and (a)(90) as paragraphs 
(a)(91) and (a)(92);
    c. By redesignating paragraphs (a)(54) through (a)(88) as 
paragraphs (a)(55) through (a)(89);
    d. By adding paragraph (a)(54);
    e. By adding paragraph (a)(90); and
    f. By adding paragraph (a)(93) to read as follows:


Sec.  60.17  Incorporations by Reference.

* * * * *
    (54) ASTM D3699--08, Standard Specification for Kerosine, IBR 
approved for Sec. Sec.  60.41b of subpart Db of this part and 60.41c of 
subpart Dc of this part.
* * * * *
    (90) ASTM D6751-11, Standard Specification for Biodiesel Fuel Blend 
Stock (B100) for Middle Distillate Fuels, IBR approved for Sec. Sec.  
60.41b of subpart Db of this part and 60.41c of subpart Dc of this 
part.
* * * * *
    (94) ASTM D7467-10, Standard Specification for Diesel Fuel Oil, 
Biodiesel Blend (B6 to B20), IBR approved for Sec. Sec.  60.41b of 
subpart Db of this part and 60.41c of subpart Dc of this part.
* * * * *

Subpart D--[Amended]

    3. The heading to Subpart D is revised to read as follows:
    Subpart D--Standards of Performance for Fossil-Fuel-Fired Steam 
Generators
    4. 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 covered under either subpart Da or KKKK is not 
covered under this subpart.
    5. Section 60.41 is amended by adding the definitions of ``natural 
gas'' to read as follows:


Sec.  60.41  Definitions.

* * * * *
    Natural gas means:
    (1) A naturally occurring mixture of hydrocarbon and nonhydrocarbon 
gases found in geologic formations beneath the earth's surface, of 
which the principal constituent is methane; or
    (2) Liquid petroleum gas, as defined by the American Society of 
Testing and Materials in ASTM D1835 (incorporated by reference, see 
Sec.  60.17); or
    (3) A mixture of hydrocarbons that maintains a gaseous state at ISO 
conditions. Additionally, natural gas must either be composed of at 
least 70 percent methane by volume or have a gross calorific value 
between 34 and 43 megajoules (MJ) per dry standard cubic meter (910 and 
1,150 Btu per dry standard cubic foot).
* * * * *
    6. Section 60.42 is amended as follows:
    a. By revising paragraph (a) introductory text.
    b. By adding paragraph (d).
    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 and operator of an affected facility that combusts 
only natural gas and that is subject to a federally enforceable permit 
limiting fuel use to 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.
    7. Section 60.45 is amended as follows:
    a. By revising paragraph (a).
    b. By revising paragraphs (b) introductory text and (b)(1) through 
(b)(5).
    c. By revising paragraph (b)(6) introductory text.

[[Page 25092]]

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) 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 SO2 and 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 section 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.
* * * * *

Subpart Da--[Amended]

    8. The heading to Subpart Da is revised to read as follows:

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

    9. Section 60.40Da is amended by revising paragraph (e) and by 
adding paragraph (f) to read as follows:


Sec.  60.40Da  Applicability and designation of affected facility.

* * * * *
    (e) Applicability of the requirement 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 
(e)(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/hr) 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 and is subject to subpart KKKK of this part.
    (2) For heat recovery steam generators used 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.
    (f) General Duty to minimize emissions. At all times, the owner or 
operator 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 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.
    10. Section 60.41Da is amended by revising the definitions of 
``gaseous fuel,'' ``integrated gasification combined cycle electric 
utility steam generating unit,'' ``petroleum'' and ``steam generating 
unit,'' adding the definitions of ``affirmative defense'' and 
``petroleum coke,'' and deleting the definitions of ``dry flue gas 
desulfurization technology,'' ``emission rate period,'' and 
``responsible official'' to read as follows:


Sec.  61.41Da  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.
* * * * *
    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.
* * * * *
    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.
* * * * *

[[Page 25093]]

    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 coke is typically derived from 
oil refinery coker units or other cracking processes.
* * * * *
    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.
* * * * *
    11. Revise Sec.  60.42Da to read as follows:


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

    (a) Except as provided in paragraph (a)(4) 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 filterable PM in excess of:
    (1) 13 ng/J (0.03 lb/MMBtu) heat input;
    (2) 1 percent of the potential combustion concentration (99 percent 
reduction) when combusting solid fuel; and
    (3) 30 percent of potential combustion concentration (70 percent 
reduction) when combusting liquid fuel.
    (4) An owner or operator of an affected facility that 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 
does not use a post-combustion technology to reduce emissions of 
SO2 or PM is exempt from the PM standard specified in 
paragraphs (a)(1), (a)(2), and (a)(3) of this section:
    (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) 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 are 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 (e) 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 
filterable 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.
    (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. For an affected facility that commenced 
construction, reconstruction, or modification, 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 any gases that contain filterable PM in excess of:
    (1) 13 ng/J (0.030 lb/MMBtu) heat input, 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) An owner or operator of an affected facility than 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 is exempt from the PM standard specified in 
paragraphs (c) of this section.
    (f) Except as provided in paragraph (g) 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, modification, or reconstruction after May 3, 2011, shall 
cause to be discharged into the atmosphere from that affected facility 
any gases that contain total PM in excess of either:
    (1) For an affected facility that commenced construction or 
reconstruction 7.0 ng/J (0.055 lb/MWh) gross energy output; or
    (2) For an affected facility that commenced modification, 15 ng/J 
(0.034 lb/MMBtu) heat input.
    (g) An owner or operator of an affected facility that combusts only 
natural gas is exempt from the total PM standard specified in paragraph 
(f) of this section.
    (h) The PM emission standards under this section do not apply to an 
owner or operator of any affected facility that is operated under a PM 
commercial demonstration permit issued by the Administrator in 
accordance with the provisions of Sec.  60.47Da.
    12. Section 60.43Da is amended as follows:
    a. By revising paragraphs (a)(1) through (a)(3).
    b. By revising paragraph (f).
    c. By revising paragraph (i).
    d. By revising paragraph (j).
    e. By revising paragraph (k).

[[Page 25094]]

    f. By adding paragraph (a)(4).
    g. By adding paragraph (l).
    h. By adding paragraph (m).
    i. By adding paragraph (n).


Sec.  60.43Da  Standard 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 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 that 
commenced 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 emission limitation 
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).
    (j) 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 commenced after 
February 28, 2005, but before May 4, 2011, and that burns 75 percent or 
more (by heat input) coal refuse on a 12-month rolling average basis, 
shall cause to be discharged into the atmosphere from that affected 
facility any gases that contain SO2 in excess of the 
applicable emission limitation specified in paragraphs (j)(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) 6 percent of the potential combustion concentration (94 
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) 6 percent of the potential combustion concentration (94 
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 that commenced 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 emission limitation 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 (m) and (n) 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 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 emission limitation specified in paragraphs (l)(1) or 
(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) 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 that 
commenced construction, reconstruction, or modification commenced after 
May 3, 2011, and that burns 75 percent or more (by heat input) coal 
refuse on a 12-month rolling average basis, shall caused to be 
discharged into the atmosphere from that affected facility any gases 
that contain SO2 in excess of the applicable emission 
limitation specified in paragraphs (m)(1) or (2) of this section.
    (1) For an affected facility which commenced construction or 
reconstruction, any gases that contain SO2 in excess of 
either:
    (i) 180 ng/J (1.4 lb/MWh) gross energy output; or
    (ii) 6 percent of the potential combustion concentration (94 
percent reduction).
    (2) For an affected facility which commenced modification, any 
gases that contain SO2 in excess of either:

[[Page 25095]]

    (i) 180 ng/J (1.4 lb/MWh) gross energy output; or
    (ii) 10 percent of the potential combustion concentration (90 
percent reduction).
    (n) 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 that commenced 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 emission limitation 
specified in paragraphs (n)(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.
    13. Section 60.44Da is amended:
    a. By revising paragraph (a) introductory text.
    b. By revising paragraph (b).
    c. By revising paragraph (d).
    d. By revising paragraph (e).
    e. By revising paragraph (f).
    f. By adding paragraph (g).
    g. By adding paragraph (h).


Sec.  60.44Da  Standard for nitrogen oxides (NO).

    (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 subject to the provisions of this 
subpart shall cause to be discharged into the atmosphere from any 
affected facility, except as provided under paragraphs (b), (d), (e), 
and (f) of this section, any gases that contain NOX 
(expressed as NO2) in excess of the following emission 
limits:
* * * * *
    (b) The NOX emission limitations 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.
    (d)(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 of an affected facility that 
commenced construction after July 9, 1997, but before March 1, 2005 
shall cause to be discharged into the atmosphere any gases that contain 
NOX (expressed as NO2) in excess of 200 ng/J (1.6 
lb/MWh) gross energy output, except as provided under Sec.  60.48Da(k).
    (2) 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 affected facility for which 
reconstruction commenced after July 9, 1997, but before March 1, 2005 
shall cause to be discharged into the atmosphere any gases that contain 
NOX (expressed as NO2) in excess of 65 ng/J (0.15 
lb/MMBtu) heat input.
    (e) 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, 
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 emission limitation specified in paragraphs (e)(1) through 
(3) of this section.
    (1) For an affected facility which commenced construction, any 
gases that contain NOX (expressed as NO2) in 
excess of 130 ng/J (1.0 lb/MWh) gross energy output, except as provided 
under Sec.  60.48Da(k).
    (2) For an affected facility which commenced reconstruction, any 
gases that contain NOX (expressed as NO2) 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 (expressed as NO2) 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 30-day 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) Compliance with the emission limitations under this section are 
determined on a 30-boiler operating day rolling average basis, except 
as provided under Sec.  60.48Da(j)(1).
    (h) 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 88 ng/J (0.70 lb/MWh) gross energy output.


Sec.  60.45Da  [Removed and Reserved]

    14. Remove and reserve Sec.  60.45Da.
    15. Section 60.47Da is amended as follows:
    a. By adding paragraph (f).
    b. By adding paragraph (g).
    c. By adding paragraph (h).
    d. By adding paragraph (i).
Section 60.47Da Commercial demonstration permit.
* * * * *
    (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

[[Page 25096]]

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 15 ng/J (0.034 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 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 controls 
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) gross 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.

------------------------------------------------------------------------
                                                           Equivalent
                                                           electrical
          Technology                  Pollutant           capacity (MW
                                                           electrical
                                                             output)
------------------------------------------------------------------------
Multi-pollutant Emission       SO2....................             1,000
 Control.
Multi-pollutant Emission       NOX....................             1,000
 Control.
Multi-pollutant Emission       PM.....................             1,000
 Control.
Pressurized Fluidized Bed      SO2....................             1,000
 Combustion.
Pressurized Fluidized Bed      NOX....................             1,000
 Combustion.
Pressurized Fluidized Bed      PM.....................             1,000
 Combustion.
Advanced Combustion Controls.  NOX....................             1,000
------------------------------------------------------------------------

    16. Section 60.48Da is amended as follows:
    a. By revising paragraph (c).
    b. By revising paragraph (g).
    c. By revising paragraph (k)(1)(i).
    d. By revising paragraph (k)(1)(ii).
    e. By revising paragraph (k)(2)(i).
    f. By revising paragraph (k)(2)(iv).
    g. By removing and reserving paragraph (l).
    h. By revising paragraph (n).
    i. By revising paragraphs (p)(5), (p)(7), and (p)(8).
    j. By adding paragraph (r).
Section 60.48a Compliance provisions.
* * * * *
    (c) For affected facilities that commenced construction, 
modification, or reconstruction before May 4, 2011, the PM emission 
standards under Sec.  60.42Da, and the NOX emission 
standards under Sec.  60.44Da apply at all times except during periods 
of startup, shutdown, or malfunction. The sulfur dioxide emission 
standards under Sec.  60.43Da apply at all times except during periods 
of startup, shutdown, or when both emergency conditions exist and the 
procedures under paragraph (d) of this section are implemented. For 
affected facilities that commence construction, modification, or 
reconstruction after May 3, 2011, the PM emission standards under Sec.  
60.42Da, the NOX emission standards under Sec.  60.44Da, and 
the sulfur dioxide emission standards under Sec.  60.43Da apply at all 
times.
* * * * *
    (g) The owner or operator of an affected facility subject to 
emission limitations in this subpart shall determine compliance as 
follows:
    (1) For affected facilities that commenced construction, 
modification, or reconstruction before May 4, 2011, compliance with 
applicable 30 boiler operating day rolling average SO2 and 
NOX emission limitations 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, malfunction (NOX 
only), or emergency conditions (SO2 only). For affected 
facilities that commence construction, modification, or reconstruction 
after May 3, 2011, compliance with applicable 30 boiler operating day 
rolling average SO2 and NOX emission limitations 
is determined by dividing the sum of all the SO2 and 
NOX emissions for the 30 successive boiler operating days 
divided by the sum of all the gross useful output for the 30 successive 
boiler operating days.
    (2) For affected facilities that commenced construction, 
modification, or reconstruction 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 that commence construction, modification, or 
reconstruction 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.
    (3) For affected facilities that commenced construction, 
modification, or reconstruction before May 4, 2011 compliance with 
applicable daily average PM emission limitations 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. For affected facilities that commence 
construction, modification, or reconstruction after May 3, 2011, 
compliance with applicable daily average PM emission limitations is 
determined by calculating the sum of all PM emissions for PM each 
boiler operating day divided by the sum of all the gross useful output 
for PM each boiler operating day, except for data obtained during 
malfunction. 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.
* * * * *
    (k) * * *
    (1) * * *
    (i) The emission rate (E) of NOX shall be computed using 
Equation 2 in this section:

[[Page 25097]]

[GRAPHIC] [TIFF OMITTED] TP03MY11.012

Where:

E = Emission rate of NOX from the duct burner, ng/J (lb/
MWh) gross 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/hr (dscf/hr);
Qte = Average hourly volumetric flow rate of exhaust gas 
from combustion turbine, dscm/hr (dscf/hr);
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] TP03MY11.013

Where:

E = Emission rate of NOX from the duct burner, ng/J (lb/
MWh) gross 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/hr (dscf/hr); 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/hr) 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] TP03MY11.014

Where:

E = Emission rate of NOX from the duct burner, ng/J (lb/
MWh) gross 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/hr (MMBtu/hr); and
Occ = Average hourly gross energy output from entire 
combined cycle unit, J/h (MW).
* * * * *
    (n) Compliance provisions for sources subject to Sec.  
60.42Da(c)(1). The owner or operator of an affected facility subject to 
Sec.  60.42Da(c)(1) 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 divided by the average hourly gross energy output 
(measured according to the provisions of Sec.  60.49Da(k)).
* * * * *
    (p) * * *
    (5) At a minimum, non-out-of-control valid 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 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) Affirmative Defense for Exceedance of Emission Limit During 
Malfunction. In response to an action to enforce the standards set 
forth in paragraph Sec. Sec.  60.42Da, 60.43Da, and 60.44Da, 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. 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 (b) 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 emission limitations 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

[[Page 25098]]

methods and engineering judgment, the amount of excess emissions that 
were the result of the malfunction.
    (2) The owner or operator of the facility 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, 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 standards in Sec. Sec.  60.42Da, 
60.43Da, and 60.44Da 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 within 45 days of the initial occurrence of the 
exceedance.
    17. Section 60.49Da is amended as follows:
    a. By revising paragraphs (a)(1), (a)(2), and (a)(3) introductory 
text.
    b. By revising paragraphs (b) introductory text and (b)(2).
    c. By revising paragraph (e).
    d. By revising paragraph (k) introductory text.
    e. By revising paragraph (l).
    f. By removing and reserving paragraph (p).
    g. By removing and reserving paragraph (q).
    h. By removing and reserving paragraph (r).
    i. By revising paragraph (t).
    j. By revising paragraphs (u)(1)(iii) and (u)(4).


Sec.  60.49Da  Emission monitoring.

    (a) * * *
    (1) Except as provided for in paragraph (a)(2) 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; or
    (A) No post-combustion technology (except a wet scrubber) is used 
for reducing PM, SO2, or carbon monoxide (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.
    (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 operators 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.
* * * * *
    (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/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, malfunction, 
and emergency conditions, 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 output for sources 
demonstrating compliance with an output-based standard.
* * * * *
    (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 CD assessment, 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 emission limitation 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.

[[Page 25099]]

    (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).
* * * * *
    (4) As of January 1, 2012 and within 60 days after the date of 
completing each performance test, as defined in Sec.  63.2, 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.
    18. Section 60.50Da is amended as follows:
    a. By revising paragraphs (b)(2) and (b)(4).
    b. By removing paragraph (g).
    c. By removing paragraph (h).
    d. By removing paragraph (i).


Sec.  60.50Da  Compliance determination procedures and methods.

* * * * *
    (b) * * *
    (2) For the filterable particular matter concentration, Method 5 of 
appendix A of this part shall be used at affected facilities without 
wet FGD systems and Method 5B of appendix A of this part shall be used 
after wet FGD systems.
* * * * *
    (4) Total particular matter concentration consists of the sum of 
the filterable and condensable fractions. The condensable fraction 
shall be measured using Method 202 of appendix M of part 51, and the 
filterable fraction shall be measured using Method 5 of appendix A of 
this part.
* * * * *
    19. Section 60.51Da is amended as follows:
    a. By revising paragraph (a).
    b. By removing and reserving paragraph (g).
    c. By revising paragraph (k).


Sec.  60.51  Da Reporting requirements.

    (a) For SO2, NOX, and PM emissions, the 
performance test data from the initial and subsequent performance test 
and from the performance evaluation of the continuous monitors 
(including the transmissometer) are submitted to the Administrator.
* * * * *
    (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), (g), 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(a)  [Removed and reserved]

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

Subpart Db--[Amended]

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


Sec.  60.40b  Applicability and delegation of affected facility.

* * * * *
    (c) Affected facilities that also meet the applicability 
requirements under subpart J or subpart Ja (Standards of performance 
for petroleum refineries) are subject to the PM and NOX 
standards under this subpart and the SO2 standards under 
subpart J or subpart Ja.
* * * * *
    (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/hr) 
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 (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.
* * * * *
    22. Section 60.41b is amended by revising the definition of 
``distillate oil'' 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), kerosene, 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).
* * * * *
    23. Section 60.44b is amended by revising paragraphs (c) and (d) to 
read as follows:


Sec.  60.44b  Standard for nitrogen oxides (NO).

* * * * *
    (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, or a mixture of these fuels with 
natural gas, and wood, municipal-type solid waste, 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 or oil, or 
mixtures of these fuels with natural gas combusted in the affected 
facility, as determined pursuant to paragraph (a) or (b) of this 
section, unless the affected facility has an annual capacity factor for 
coal or oil, or mixture of these fuels

[[Page 25100]]

with 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 for 
coal, oil, or a mixture of these fuels with natural gas.
    (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 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.
* * * * *
    24. 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 60 days after the date of 
completing each performance test, as defined in Sec.  63.2, 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.
    25. Section 60.48b is amended as follows:
    a. By revising paragraphs (a) introductory text and (a)(1)(i).
    b. By revising paragraph (j) introductory text.
    c. By revising paragraph (j)(5).
    d. By revising paragraph (j)(6).
    e. By adding paragraph (j)(7).


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;
* * * * *
    (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.
* * * * *

Subpart Dc--[Amended]

    26. Section 60.40c is amended as follows:
    a. By revising paragraph (e).
    b. By revising paragraph (f).
    c. By revising paragraph (g).


Sec.  60.40c  Applicability and delegation of authority.

* * * * *
    (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/hr) heat input of fossil fuel but less than or 
equal to 29 MW (100 MMBtu/hr) 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 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 of 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.
    27. Section 60.41c is amended by removing the definition of 
``Cogeneration'' and revising the definition of ``Distillate oil'' to 
read as follows:


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

[[Page 25101]]

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), kerosene, 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).
* * * * *
    28. Section 60.42c is amended as follows:
    a. By revising paragraph (d).
    b. By revising paragraph (h) introductory text.
    c. By revising paragraph (h)(3).
    d. By adding paragraph (h)(4).


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

* * * * *
    (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.
* * * * *
    (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/hr).
    (4) Other fuels-fired affected facilities with heat input 
capacities between 2.9 and 8.7 MW (10 and 30 MMBtu/hr).
* * * * *
    29. Section 60.45c is amended by revising paragraph (c)(14) to read 
as follows:


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

* * * * *
    (c)(14) As of January 1, 2012, and within 60 days after the date of 
completing each performance test, as defined in Sec.  63.2, 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.
* * * * *
    30. Section 60.47c is amended as follows:
    a. By revising paragraphs (a) introductory text and (a)(1)(i).
    b. By revising paragraph (f).
    c. By revising paragraph (g).
    d. By adding paragraph (h).


Sec.  60.47c  Emission monitoring for particulate matter.

    (a) Except as provided in paragraphs (c), (d), (e), (f), (g), and 
(h) 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), (f), or (g) 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;
* * * * *
    (f) Owners and operators of an affected facility that is subject to 
an opacity standard in Sec.  60.43c(c) and that 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 is not required to operate a COMS.
    (g) 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.
    (h) Owners and operators of an affected facility that is subject to 
an opacity standard in Sec.  60.43c(c) and that burns only gaseous 
fuels and/or fuel oils that contain less than or equal to 0.5 weight 
percent sulfur and 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.

Subpart HHHH--[Removed and Reserved]

    31. Subpart HHHH is removed and reserved.

PART 63--[AMENDED]

    32. The authority citation for part 63 continues to read as 
follows:

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

    33. 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?

[[Page 25102]]

63.9983 Are any EGUs not subject to this subpart?
63.9984 When do I have to comply with this subpart?

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, Fuel Analyses, 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, fuel 
analyses, or tune-ups?
63.10007 What methods and other procedures must I use for the 
performance tests?
63.10008 What fuel analyses and procedures must I use for the 
performance tests?
63.10009 May I use emission 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 and work practice standards?
63.10022 How do I demonstrate continuous compliance under the 
emission averaging provision?

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--Fuel Analysis Requirements
Table 7 to Subpart UUUUU of Part 63--Establishing Operating Limits
Table 8 to Subpart UUUUU of Part 63--Demonstrating Continuous 
Compliance
Table 9 to Subpart UUUUU of Part 63--Reporting Requirements
Table 10 to Subpart UUUUU of Part 63--Applicability of General 
Provisions to Subpart UUUUU
Appendix A to Subpart UUUUU--Hg 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). 
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.


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

    (a) This subpart applies to each individual or group of one 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 Sec.  63.10042.
    (2) The affected source of this subpart is each new or 
reconstructed coal- or oil-fired EGU as defined in Sec.  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 utility steam generating unit that has switched 
completely to burning a different coal rank or fuel type is considered 
to be an existing affected source under this subpart.


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

    The types of EGUs listed in paragraphs (a) through (c) 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), covered by 40 
CFR part 63, subpart YYYY.
    (b) Any 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.
    (c) Any EGU that has the capability of combusting more than 73 MWe 
(250 million Btu/hr, MMBtu/hr) heat input (equivalent to 25 MWe output) 
of coal or oil but did not fire 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. 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).


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 [DATE THE FINAL RULE IS PUBLISHED IN THE FEDERAL 
REGISTER] or upon startup of your EGU, whichever is later.
    (b) If you have an existing EGU, you must comply with this subpart 
no later than [3 YEARS AFTER DATE THE FINAL RULE IS PUBLISHED IN THE 
FEDERAL REGISTER].
    (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.

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

[[Page 25103]]

(a)(2) of this section and as defined in Sec.  63.10042.
    (1) EGUs designed for coal = 8,300 Btu/lb, and
    (2) EGUs designed for coal < 8,300 Btu/lb. (b) Oil-fired EGUs are 
subcategorized as noted in paragraphs (b)(1) through (b)(2) of this 
section and as defined in Sec.  63.10042.
    (1) EGUs designed to burn liquid oil, and
    (2) 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 paragraph (a)(1)(i) and 
(ii) or under Sec.  63.10009.
    (i) You may not use the alternate SO2 limit if your 
coal-fired EGU does not have a system using wet or dry flue gas 
desulfurization technology installed on the unit.
    (ii) You may not use the alternate SO2 limit if your 
oil-fired EGU does not have a system using wet or dry flue gas 
desulfurization technology installed on the unit.
    (iii) You must operate the wet or dry flue gas desulfurization 
technology installed on the unit at all times in order to qualify to 
use the alternate SO2 limit.
    (2) You must meet each operating limit in Table 4 to this subpart 
that applies to your EGU. If you use a control device or combination of 
control devices not covered in Table 4 to this subpart, or you wish to 
establish and monitor an alternative operating limit and alternative 
monitoring parameters, you must apply to the EPA Administrator for 
approval of alternative monitoring under Sec.  63.8(f).
    (b) As provided in Sec.  63.6(g), EPA may approve use of an 
alternative to the work practice standards in this section.

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.
    (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. For non-
mercury HAP metals, you demonstrate continuous compliance through use 
of a particulate matter (PM) CEMS; initial compliance is determined by 
establishing an operational limit for filterable PM obtained during 
total PM emissions testing. As an alternative to using a PM CEMS, you 
may demonstrate initial and continuous compliance by conducting total 
HAP metals testing or individual non-mercury (Hg) metals testing. For 
acid gases, you demonstrate initial and continuous compliance through 
use of a continuous hydrogen chloride (HCl) CEMS. As an alternative to 
HCl CEMS, you may demonstrate initial and continuous compliance by 
conducting performance testing. As another alternative to HCl CEMS, you 
may demonstrate initial and continuous compliance through use of a 
certified sulfur dioxide (SO2) CEMS, provided the unit has a 
system using wet or dry flue gas desulfurization technology. For 
mercury (Hg), if your unit does not qualify as a low emitting EGU 
(LEE), you must demonstrate initial and continuous compliance through 
use of a Hg CEMS or a sorbent trap monitoring system.
    (2) For liquid oil-fired units, you must demonstrate initial and 
continuous compliance for HCl, hydrogen fluoride (HF), and individual 
or total HAP metals by conducting performance testing. As an 
alternative to conducting performance testing, you may demonstrate 
compliance with the applicable emissions limit for HCl, HF, and 
individual or total HAP metals using fuel analysis provided the 
emission rate calculated according to Sec.  63.10011(c) is less than 
the applicable emission limit.
    (d) 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), or through the use of a 
sorbent trap monitoring system for Hg, 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 or sorbent trap monitoring system. This 
requirement also applies to you if you petition the EPA 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. The 
monitoring plan must address the provisions in paragraphs (d)(1) 
through (7) of this section.
    (1) Installation of the CMS 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).
    (2) Performance and equipment specifications for the sample 
interface, the pollutant concentration or parametric signal analyzer, 
and the data collection and reduction systems.
    (3) Schedule for conducting initial and periodic performance 
evaluations.
    (4) 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) 
or Appendix A to this subpart, as applicable.
    (5) Ongoing operation and maintenance procedures in accordance with 
the general requirements of Sec.  63.8(c)(1)(ii), (c)(3), and 
(c)(4)(ii) or Appendix A to this subpart, as applicable.
    (6) Conditions that define a continuous monitoring system 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) or Appendix A to this subpart, as applicable.

[[Page 25104]]

    (7) Ongoing recordkeeping and reporting procedures in accordance 
with the general requirements of Sec.  63.10(c), (e)(1), and (e)(2)(i) 
and Appendix A to this subpart, as applicable.
    (e) You must operate and maintain the CMS or sorbent trap 
monitoring system according to the site-specific monitoring plan.


Sec.  63.10001  Affirmative Defense for Exceedence of Emission Limit 
During Malfunction.

    In response to an action to enforce the standards set forth in 
paragraph 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 the respondent fails to meet its 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, the owners or operators of facilities 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 facility 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) The owner or operator of the facility experiencing an 
exceedence of its emission limit(s) during a malfunction shall notify 
the EPA Administrator by telephone or facsimile (FAX) transmission as 
soon as possible, but no later than two (2) business days after the 
initial occurrence of the malfunction, 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 EPA Administrator within 45 days of the 
initial occurrence of the exceedence 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 within 45 days of 
the initial occurrence of the exceedances.

Testing, Fuel Analyses, and Initial Compliance Requirements


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

    (a) General requirements. Affected EGUs must demonstrate initial 
compliance with each of the applicable emissions limits in Tables 1 or 
2 of this subpart through performance testing, along with one or more 
of the following activities: conducting a fuel analysis for each type 
of fuel combusted, establishing operating limits where applicable 
according to Sec.  63.10011 and Table 7 to this subpart; conducting CMS 
performance evaluations where applicable; and conducting sorbent trap 
monitoring system performance evaluations, where applicable, in 
conjunction with performance testing. If you use a CMS that measures 
pollutant concentrations directly (i.e., a CEMS or a sorbent trap 
monitoring system), the performance test consists of the first 30 
operating days of data collected with the certified monitoring system, 
after the applicable compliance date. If you use a continuous 
monitoring system that measures a surrogate for a pollutant (e.g., an 
SO2 monitor), you must perform initial emission testing 
during the same compliance test period and under the same process 
(e.g., fuel) and control device operating conditions of the pollutant 
and surrogate, in addition to conducting the initial 30-day performance 
test. If you wish to demonstrate that a unit qualifies as a low 
emitting EGU (LEE), you must conduct performance testing in accordance 
with paragraphs (k) and (l) of this section.
    (b) Performance Testing Requirements. Affected EGUs must 
demonstrate initial compliance with each of the applicable emissions 
limits in Tables 1 or 2 of this subpart by conducting performance tests 
according to Sec.  63.10007 and Table 5 to this subpart.
    (1) For affected EGUs that do not rely on CMS, sorbent trap 
monitoring systems, or 28 to 30 day Method 30B testing to demonstrate 
initial compliance, performance test data and results from a prior 
performance test may be used to demonstrate initial compliance, 
provided the performance tests meet the following conditions:
    (i) The performance test was conducted within the last twelve 
months;
    (ii) The performance test was conducted in accordance with all 
requirements contained in Sec.  63.10007 and Table 5 of this subpart; 
and
    (iii) You certify, and have and keep documentation demonstrating, 
that the EGU configuration, control devices, and materials/fuel have 
remained constant since the prior performance test was conducted.
    (2) [Reserved]
    (c) Fuel Analysis Requirements. Affected liquid oil-fired EGUs may 
choose to demonstrate initial compliance with each of the applicable 
emissions limits in Tables 1 or 2 of this subpart by conducting a fuel 
analysis for each type of fuel combusted, except

[[Page 25105]]

those affected EGUs that meet the exemptions identified in paragraphs 
(c)(4) and (5) of this section and those affected EGUs that opt to 
comply with the individual or total HAP metals limits in Tables 1 or 2 
of this subpart which must comply by conducting a fuel analysis as 
described in paragraph (c)(1) of this section.
    (1) For affected liquid oil-fired EGUs demonstrating compliance 
with the applicable emissions limits in Tables 1 or 2 of this subpart 
for HCl or individual or total HAP metals through fuel analysis, your 
initial compliance requirement is to conduct a fuel analysis for each 
type of fuel burned in your EGU according to Sec.  63.10008 and Table 6 
to this subpart and establish operating limits according to Sec.  
63.10011 and Table 8 to this subpart.
    (2) For affected liquid oil-fired EGUs that elect to demonstrate 
compliance with the applicable emissions limits in Tables 1 or 2 of 
this subpart for HF, your initial compliance requirement is to conduct 
a fuel analysis for each type of fuel burned in your EGU according to 
Sec.  63.10008 and Table 6 to this subpart and establish operating 
limits according to Sec.  63.10011 and Table 8 to this subpart.
    (3) Fuel analysis data and results from a prior fuel analysis may 
be used to demonstrate initial compliance, provided the fuel analysis 
meets the following conditions:
    (i) The fuel analysis was conducted within the last twelve months;
    (ii) The fuel analysis was conducted in accordance with all 
requirements contained in Sec.  63.10008 and Table 6 of this subpart; 
and
    (iii) You certify, and have and keep documentation demonstrating, 
that the EGU configuration, control devices, and materials/fuel have 
remained constant since the prior fuel analysis was conducted.
    (4) For affected EGUs that combust a single type of fuel, you are 
exempted from the initial compliance requirements of conducting a fuel 
analysis for each type of fuel burned in your EGU according to Sec.  
63.10008 and Table 6 to this subpart.
    (5) For purposes of this subpart, EGUs that use a supplemental fuel 
only for startup, unit shutdown, or transient flame stability purposes 
qualify as affected EGUs that combust a single type of fuel, the 
supplemental fuel is not subject to the fuel analysis requirements 
under Sec.  63.10008 and Table 6 to this subpart, and you are exempted 
from the initial compliance requirements of conducting a fuel analysis 
for each type of fuel burned in your EGU according to Sec.  63.10008 
and Table 6 to this subpart.
    (d) CMS Requirements. (1) For affected liquid oil-fired EGUs that 
elect to demonstrate initial compliance with the applicable emissions 
limits in Tables 1 or 2 of this subpart for HCl through use of HCl 
CEMS, initial compliance is determined using the average hourly HCl 
concentrations obtained during the first 30 day operating period after 
the monitoring system is certified.
    (2) For affected liquid oil-fired EGUs that elect to demonstrate 
initial compliance with the applicable emissions limits in Tables 1 or 
2 of this subpart for HF through use of HF CEMS, initial compliance is 
determined using the average hourly HF concentrations obtained during 
the first 30 day operating period after the monitoring system is 
certified.
    (3) For affected solid oil-derived fuel- or coal-fired EGUs that 
demonstrate initial compliance with the applicable emissions limits in 
Tables 1 or 2 of this subpart for HCl through use of HCl CEMS, initial 
compliance is determined using the average hourly HCl concentrations 
obtained during the first 30 day operating period after the monitoring 
system is certified.
    (4) For affected solid oil-derived fuel- or coal-fired EGUs with 
installed systems that use wet or dry flue gas desulfurization 
technology to demonstrate initial compliance with the applicable 
emissions limits in Tables 1 or 2 of this subpart for SO2 
through use of SO2 CEMS, initial compliance is determined 
using the average hourly SO2 concentrations obtained during 
the first 30 day operating period after the monitoring system is 
certified.
    (5) For affected solid oil-derived fuel- or coal-fired EGUs that 
demonstrate initial compliance with the applicable emissions limits in 
Tables 1 or 2 of this subpart for PM through use of PM CEMS, initial 
compliance is determined using the average hourly PM concentrations 
obtained during the first 30 day operating period after the monitoring 
system is certified.
    (6) For affected EGUs that demonstrate initial compliance with the 
applicable emissions limits in Tables 1 or 2 of this subpart for Hg 
through use of Hg CEMS, initial compliance is determined using the 
average hourly Hg concentrations obtained during the first 30 day 
operating period after the monitoring system is certified.
    (7) For affected EGUs that elect to demonstrate initial compliance 
with the applicable emissions limits in Tables 1 or 2 of this subpart 
for PM, non-Hg HAP metals, HCl, HF, or Hg through use of CPMS, initial 
compliance is determined using the average hourly PM, non-Hg HAP 
metals, HCl, HF, or Hg concentrations obtained during the first 30 day 
operating period.
    (e) Sorbent Trap Monitoring System Requirements. For affected EGUs 
that demonstrate initial compliance with the applicable emissions 
limits in Tables 1 or 2 of this subpart for Hg through use of Hg 
sorbent trap monitoring system, initial compliance is determined using 
the average hourly Hg concentrations obtained during the first 30 day 
operating period.
    (f) Tune-ups. For affected EGUs subject to work practice standards 
in Table 3 of this subpart, your initial compliance requirement is to 
conduct a tune-up of your EGU according to Sec.  63.10021(a)(16)(i) 
through (vi).
    (g) For existing affected sources, you must demonstrate initial 
compliance no later than 180 days after the compliance 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 10 to this 
subpart.
    (h) If your new or reconstructed affected source commenced 
construction or reconstruction between May 3, 2011 and [DATE 60 DAYS 
AFTER PUBLICATION OF THE FINAL RULE IN THE FEDERAL REGISTER], you must 
demonstrate initial compliance with either the proposed emission limits 
or the promulgated emission limits no later than 180 days after [DATE 
60 DAYS AFTER PUBLICATION OF THE FINAL RULE IN THE FEDERAL REGISTER] or 
within 180 days after startup of the source, whichever is later, 
according to Sec.  63.7(a)(2)(ix).
    (i) If your new or reconstructed affected source commenced 
construction or reconstruction between May 3, 2011, and [DATE 60 DAYS 
AFTER PUBLICATION OF THE FINAL RULE IN THE FEDERAL REGISTER], and you 
chose 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 [DATE 60 DAYS 
AFTER PUBLICATION OF THE FINAL RULE IN THE FEDERAL REGISTER] or within 
3 years after startup of the affected source, whichever is later.
    (j) If your new or reconstructed affected source commences 
construction or reconstruction after [DATE 60 DAYS AFTER PUBLICATION OF 
THE FINAL RULE IN THE FEDERAL REGISTER], you must demonstrate initial 
compliance with the promulgated emission limits no later than 180 days 
after startup of the source.

[[Page 25106]]

    (k) Low emitting EGU. Your existing EGU may qualify for low 
emitting EGU (LEE) status provided that initial performance test data 
that meet the requirements of Sec.  63.10005(b) and paragraph (l) of 
this section demonstrate:
    (1) With the exception of mercury, emissions less than 50 percent 
of the appropriate emissions limitation, or
    (2) For mercury, emissions less than 10 percent of the mercury 
emissions limitation or less than 22.0 pounds per year. Only existing 
affected units may qualify for LEE status for Hg. When qualifying for 
LEE status for Hg emissions less than 22.0 pounds per year, the 
affected unit must also demonstrate compliance with the applicable 
emission limitation.
    (3) The following provisions apply in demonstrating that a unit 
qualifies as a LEE. For all pollutants or surrogates except for Hg, 
conduct the initial performance tests as described in Sec.  63.10007 
but note that the required minimum sampling volume must be increased 
nominally by a factor of two; follow the instructions in Table 5 to 
this subpart to convert the test data to the units of the applicable 
standard. For Hg, you must conduct a 28 to 30 operating day performance 
test, using Method 30B in appendix A-8 to part 60 of this chapter, to 
determine Hg concentration. 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-8 to part 60 of this chapter and 
conduct at least three nominally equal length test runs over the 28 to 
30 day test period. You may not use a pair of sorbent traps to sample 
the stack gas for more than 10 days. Collect diluent gas data over the 
corresponding time period, and if preferred for calculation of pounds 
per year of Hg, stack flow rate data using Method 2 in appendix A-1 to 
part 60 of this chapter or a certified flow rate monitor and moisture 
data using Method 4 in appendix A-1 to part 60 of this chapter or a 
moisture monitor. Record parametric data during each performance test, 
to establish operating limits, in accordance with the applicable 
provisions of Sec.  63.10010(k)(3). Calculate the average Hg 
concentration, in [mu]g/m\3\, for the 28 to 30 day performance test, as 
the arithmetic average of all sorbent trap results. Calculate the 
average CO2 or O2 concentration for the test 
period. Use the average Hg concentration and diluent gas values to 
express the performance test results in units of lb of Hg/TBtu, as 
described in section 6.2.1 of appendix A to this subpart, and, if 
elected, pounds of Hg per year, using the expected fuel input over a 
year period. You may also opt to calculate pounds of Hg per year using 
the average Hg concentration, average stack gas flow rate, average 
stack gas moisture, and maximum operating hours per year.
    (1) Startup and Shutdown default values for calculations. For the 
purposes of this rule and only during periods of startup or shutdown, 
use a default diluent gas concentration value of 10.0 percent 
O2 or the corresponding fuel-specific CO2 
concentration in calculating emissions in units of lb/MMBtu or lb/TBtu. 
For calculating emissions in units of lb/MWh or lb/GWh only during 
startup or shutdown periods, use a nominal electrical production rate 
equal to 5 percent of rated capacity.


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

    (a) For solid oil-derived fuel- and coal-fired EGUs using total PM 
emissions as a surrogate for non-Hg HAP metals emissions and using PM 
CEMS to measure filterable PM emissions as a surrogate for total PM 
emissions, you must conduct all applicable performance tests for PM and 
non-Hg HAP metals emissions during the same compliance test period and 
under the same process (e.g., fuel) and control device operating 
conditions according to Table 5 and Sec.  63.10007 at least every 5 
years.
    (b) For solid oil-derived fuel- and coal-fired EGUs with installed 
systems that use wet or dry flue gas desulfurization technology using 
sulfur dioxide (SO2) emissions as a surrogate for HCl 
emissions and using SO2 CEMS to measure SO2 
emissions, you must conduct all applicable performance tests for 
SO2 and HCl emissions during the same compliance test period 
and under the same process (e.g., fuel) and control device operating 
conditions according to Table 5 and Sec.  63.10007 at least every 5 
years.
    (c) For affected units meeting the LEE requirements of Sec.  
63.1005(k), provided that the unit operates within the operating limits 
established during the initial performance test, you need only repeat 
the performance test once every 5 years according to Table 5 and Sec.  
63.10007 and conduct fuel sampling and analysis according to Table 6 
and Sec.  63.10008 at least every month. However, if the unit fails to 
operate within the operating limits during any 5 year compliance 
period, LEE status is lost. If this should occur:
    (1) For all pollutants or surrogates except for Hg, you must 
initiate periodic emission testing, as required in the applicable 
paragraph(s) of this section, within a six month period.
    (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 a one year period.
    (d) For solid oil-derived fuel- and coal-fired EGUs without PM CEMS 
but with PM emissions control devices, you must conduct all applicable 
performance tests for PM and non-Hg HAP metals emissions during the 
same compliance test period and under the same process (e.g., fuel) and 
control device operating conditions according to Table 5 and Sec.  
63.10007 at least every year and you must conduct non-Hg HAP metals 
emissions testing according to Table 5 and Sec.  63.10007 at least 
every other month.
    (e) For solid oil-derived fuel- and coal-fired EGUs without PM CEMS 
and without PM emissions control devices, you must conduct all 
applicable performance tests for non-Hg HAP metals emissions according 
to Table 5 and Sec.  63.10007 at least every month.
    (f) For liquid oil-fired EGUs with non-Hg HAP metals control 
devices, you must conduct all applicable performance tests for 
individual or total HAP metals emissions according to Table 5 and Sec.  
63.10007 at least every other month.
    (g) For liquid oil-fired EGUs without non-Hg HAP metals control 
devices, you must conduct all applicable performance tests for 
individual or total HAP metals emissions according to Table 5 and Sec.  
63.10007 at least every month.
    (h) For solid oil-derived fuel- and coal-fired EGUs without 
SO2 CEMS but with installed systems that use wet or dry flue 
gas desulfurization technology, you must conduct all applicable 
performance tests for SO2 and HCl emissions during the same 
compliance test period and under the same process (e.g., fuel) and 
control device operating conditions according to Table 5 and Sec.  
63.10007 at least every year and you must conduct SO2 
emissions testing according to Sec.  63.10007 at least every other 
month.
    (i) For solid oil-derived fuel- and coal-fired EGUs without 
SO2 CEMS and without installed systems that use wet or dry 
flue gas desulfurization technology, you must conduct all applicable 
performance tests for SO2 and HCl emissions during the same 
compliance test period and under the same process (e.g., fuel) and 
control device operating conditions according to Table 5 and Sec.  
63.10007 at least every year and you must conduct HCl

[[Page 25107]]

emissions testing according to Table 5 and Sec.  63.10007 at least 
every month.
    (j) For solid oil-derived fuel- and coal-fired EGUs without HCl 
CEMS but with HCl emissions control devices, you must conduct all 
applicable performance tests for HCl emissions according to Table 5 and 
Sec.  63.10007 at least every other month.
    (k) For solid oil-derived fuel- and coal-fired EGUs without HCl 
CEMS and without HCl emissions control devices, you must conduct all 
applicable performance tests for HCl emissions according to Table 5 and 
Sec.  63.10007 at least every month.
    (l) For liquid oil-fired EGUs without HCl and HF CEMS but with HCl 
and HF emissions control devices, you must conduct all applicable 
performance tests for HCl and HF emissions according to Table 5 and 
Sec.  63.10007 at least every other month.
    (m) For liquid oil-fired EGUs without HCl and HF CEMS and without 
HCl and HF emissions control devices, you must conduct all applicable 
performance tests for HCl and HF emissions according to Table 5 and 
Sec.  63.10007 at least every month.
    (n) Unless you follow the requirements listed in paragraphs (o) 
through (q) of this section, performance tests required at least every 
5 years must be completed within 58 to 62 months after the previous 
performance test; performance tests required at least every year must 
be completed no more than 13 months after the previous performance 
test; performance tests required at least every 2 months must be 
completed between 52 and 69 days after the previous performance test; 
and performance tests required at least every month must be completed 
between 21 and 38 days after the previous performance test.
    (o) For EGUs with annual or more frequent performance testing 
requirements, you can conduct performance stack tests less often for a 
given pollutant if your performance stack tests for the pollutant for 
at least 3 consecutive years show that your emissions are at or below 
50 percent of the emissions limit, and if there are no changes in the 
operation of the affected source or air pollution control equipment 
that could increase emissions. In this case, you do not have to conduct 
a performance test for that pollutant for the next 2 years. You must 
conduct a performance test during the third year and no more than 37 
months after the previous performance test. If you elect to demonstrate 
compliance using emission averaging under Sec.  63.10009, you must 
continue to conduct performance stack tests at the appropriate 
frequency given in section (c) through (m) of this paragraph.
    (p) If your EGU continues to meet the emissions limit for the 
pollutant, you may choose to conduct performance stack tests for the 
pollutant every third year if your emissions are at or below the 
emission limit, and if there are no changes in the operation of the 
affected source or air pollution control equipment that could increase 
emissions, but each such performance test must be conducted no more 
than 37 months after the previous performance test. If you elect to 
demonstrate compliance using emission averaging under Sec.  63.10009, 
you must continue to conduct performance stack tests at the appropriate 
frequency given in section (c) through (m) of this paragraph.
    (q) If a performance test shows emissions in excess of 50 percent 
of the emission limit, you must conduct performance tests at the 
appropriate frequency given in section (c) through (m) of this 
paragraph for that pollutant until all performance tests over a 
consecutive 3-year period show compliance.
    (r) If you are required to meet an applicable tune-up work practice 
standard, you must conduct a performance tune-up according to Sec.  
63.10007. Each performance tune-up specified in Sec.  63.10007 must be 
no more than 18 months after the previous performance tune-up.
    (s) If you demonstrate compliance with the Hg, individual or total 
non-Hg HAP metals, HCl, or HF emissions limit based on fuel analysis, 
you must conduct a monthly fuel analysis according to Sec.  63.10008 
for each type of fuel burned. If you burn a new type of fuel, you must 
conduct a fuel analysis before burning the new type of fuel in your 
EGU. You must still meet all applicable continuous compliance 
requirements in Sec.  63.10021.
    (t) You must report the results of performance tests, performance 
tune-ups, and fuel analyses within 60 days after the completion of the 
performance tests, performance tune-ups, and fuel analyses. This report 
must also verify that the operating limits for your affected EGU have 
not changed or provide documentation of revised operating parameters 
established according to Sec.  63.10011 and Table 7 to this subpart, as 
applicable. 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) You must conduct all performance tests according to Sec.  
63.7(c), (d), (f), and (h). You must also develop a site-specific test 
plan according to the requirements in Sec.  63.7(c).
    (b) You must conduct each performance test according to the 
requirements in Table 5 to this subpart.
    (c) You must conduct each performance test under the specific 
conditions listed in Tables 5 and 7 to this subpart. You must conduct 
performance tests at the maximum normal operating load while burning 
the type of fuel or mixture of fuels that has the highest content of 
chlorine, fluorine, non-Hg HAP metals, and Hg, and you must demonstrate 
initial compliance and establish your operating limits based on these 
tests. These requirements could result in the need to conduct more than 
one performance test. Moreover, should you desire to have differing 
operating limits which correspond to loads other than maximum normal 
operating load, you should conduct testing at those other loads to 
determine those other operating limits. Following each performance test 
and until the next performance test, you must comply with the operating 
limit for operating load conditions specified in Table 4 of this 
subpart.
    (d) For performance testing that does not involve CMS or a sorbent 
trap monitoring system, you must conduct three separate test runs for 
each performance test required, as specified in Sec.  63.7(e)(3). Each 
test run must comply with the minimum applicable sampling times or 
volumes specified in Tables 1 and 2 to this subpart. For performance 
testing that involves CMS or a sorbent trap monitoring system, 
compliance shall be determined as described in Sec.  63.10005(d) and 
(e).
    (e) To determine compliance with the emission limits, you must use 
the F-Factor methodology and equations in sections 12.2 and 12.3 of EPA 
Method 19 at 40 CFR part 60, Appendix A-7 of this chapter to convert 
the measured PM concentrations, the measured HCl and HF concentrations, 
the measured SO2 concentrations, the measured individual and 
total non-Hg HAP metals concentrations, and the measured Hg 
concentrations that result from the initial performance test to pounds 
per million Btu (lb/MMBtu) (pounds per trillion Btu, lb/TBtu, for Hg) 
heat input emission rates using F-factors.
    (f) Performance tests shall be conducted under such conditions as 
the EPA Administrator specifies to the owner or operator based on

[[Page 25108]]

representative performance of the affected source for the period being 
tested. Upon request, the owner or operator shall make available to the 
EPA Administrator such records as may be necessary to determine the 
conditions of performance tests.


Sec.  63.10008  What fuel analyses and procedures must I use for the 
performance tests?

    (a) You must conduct performance fuel analysis tests according to 
the procedures in paragraphs (b) through (e) of this section and Table 
6 to this subpart, as applicable. You are not required to conduct fuel 
analyses for fuels used only for startup, unit shutdown, or transient 
flame stability purposes.
    (b) You must develop and submit a site-specific fuel analysis plan 
to the EPA Administrator for review and approval according to the 
following procedures and requirements in paragraphs (b)(1) and (2) of 
this section.
    (1) You must submit the fuel analysis plan no later than 60 days 
before the date that you intend to demonstrate compliance.
    (2) You must include the information contained in paragraphs 
(b)(2)(i) through (vi) of this section in your fuel analysis plan.
    (i) The identification of all fuel types anticipated to be burned 
in each EGU.
    (ii) For each fuel type, the notification of whether you or a fuel 
supplier will be conducting the fuel analysis.
    (iii) For each fuel type, a detailed description of the sample 
location and specific procedures to be used for collecting and 
preparing the composite samples if your procedures are different from 
paragraph (c) or (d) of this section. Samples should be collected at a 
location that most accurately represents the fuel type, where possible, 
at a point prior to mixing with other dissimilar fuel types.
    (iv) For each fuel type, the analytical methods from Table 6, with 
the expected minimum detection levels, to be used for the measurement 
of chlorine, fluorine, non-Hg HAP metals, or Hg.
    (v) If you request to use an alternative analytical method other 
than those required by Table 6 to this subpart, you must also include a 
detailed description of the methods and procedures that you are 
proposing to use. Methods in Table 6 shall be used until the requested 
alternative is approved.
    (vi) If you will be using fuel analysis from a fuel supplier in 
lieu of site-specific sampling and analysis, the fuel supplier must use 
the analytical methods required by Table 6 to this subpart.
    (c) At a minimum, you must obtain three composite fuel samples for 
each fuel type according to the procedures in paragraph (c)(1) or (2) 
of this section.
    (1) If sampling from a belt (or screw) feeder, collect fuel samples 
according to paragraphs (c)(1)(i) and (ii) of this section.
    (i) Stop the belt and withdraw a 6-inch wide sample from the full 
cross-section of the stopped belt to obtain a minimum two pounds of 
sample. You must collect all the material (fines and coarse) in the 
full cross-section. You must transfer the sample to a clean plastic 
bag.
    (ii) Each composite sample will consist of a minimum of three 
samples collected at approximately equal 1-hour intervals during the 
testing period.
    (2) If sampling from a fuel pile or truck, you must collect fuel 
samples according to paragraphs (c)(2)(i) through (iii) of this 
section.
    (i) For each composite sample, you must select a minimum of five 
sampling locations uniformly spaced over the surface of the pile.
    (ii) At each sampling site, you must dig into the pile to a depth 
of 18 inches. You must insert a clean flat square shovel into the hole 
and withdraw a sample, making sure that large pieces do not fall off 
during sampling.
    (iii) You must transfer all samples to a clean plastic bag for 
further processing.
    (d) You must prepare each composite sample according to the 
procedures in paragraphs (d)(1) through (7) of this section.
    (1) You must thoroughly mix and pour the entire composite sample 
over a clean plastic sheet.
    (2) You must break sample pieces larger than 3 inches into smaller 
sizes.
    (3) You must make a pie shape with the entire composite sample and 
subdivide it into four equal parts.
    (4) You must separate one of the quarter samples as the first 
subset.
    (5) If this subset is too large for grinding, you must repeat the 
procedure in paragraph (d)(3) of this section with the quarter sample 
and obtain a one-quarter subset from this sample.
    (6) You must grind the sample in a mill.
    (7) You must use the procedure in paragraph (d)(3) of this section 
to obtain a one-quarter subsample for analysis. If the quarter sample 
is too large, subdivide it further using the same procedure.
    (e) You must determine the concentration of pollutants in the fuel 
(Hg, HAP metals, and/or chlorine) in units of lb/MMBtu of each 
composite sample for each fuel type according to the procedures in 
Table 6 to this subpart.


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

    (a) As an alternative to meeting the requirements of Sec.  63.9991 
for PM, HF, HCl, non-Hg HAP metals, or Hg on an EGU-specific basis, if 
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), you may demonstrate compliance by 
emission averaging among the existing EGUs in the same subcategory, if 
your averaged emissions for such EGUs are equal to or less than the 
applicable emission limit, according to the procedures in this section.
    (b) 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 PM, 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 (c), (d), (e), (f), and (g) 
of this section.
    (c) For each existing EGU in the averaging group, the emission rate 
achieved during the initial compliance test for the HAP being averaged 
must not exceed the emission level that was being achieved on [THE DATE 
30 DAYS AFTER PUBLICATION OF THE FINAL RULE IN THE FEDERAL REGISTER] or 
the control technology employed during the initial compliance test must 
not be less effective for the HAP being averaged than the control 
technology employed on [THE DATE 30 DAYS AFTER PUBLICATION OF THE FINAL 
RULE IN THE FEDERAL REGISTER].
    (d) The averaged 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 in Sec.  63.9984.
    (e) You must demonstrate initial compliance according to paragraph 
(e)(1) or (2) of this section using the maximum normal operating load 
of each EGU and the results of the initial performance tests or fuel 
analysis.
    (1) You must use Equation 1 of this section to demonstrate that the 
PM, HF, SO2, HCl, non-Hg HAP metals, or Hg emissions from 
all existing units participating in the emissions averaging option do 
not exceed the emission limits in Table 2 to this subpart.

[[Page 25109]]

[GRAPHIC] [TIFF OMITTED] TP03MY11.015

Where:

Ave Weighted Emissions = Average weighted emissions for PM, HF, 
SO2, HCl, non-Hg HAP metals, or Hg, in units of lb/MMBtu 
(lb/TBtu for Hg) of heat input.
Er = Emissions rate (as determined during the most recent 
performance test, according to Table 5 to this subpart) for PM, HF, 
HCl, non-Hg HAP metals, or Hg or by fuel analysis for Cl, F, non-Hg 
HAP metals, or Hg as calculated by the applicable equation in Sec.  
63.10011(c) for unit, i, for PM, HF, SO2, HCl, non-Hg HAP 
metals, or Hg, in units of lb/MMBtu (lb/TBtu for Hg) of heat input.
Hm = Maximum rated heat input capacity of unit, i, in units of 
million Btu per hour.
n = Number of units participating in the emissions averaging option.

    (2) If you are not capable of monitoring heat input, and the EGU 
generates steam for purposes other than generating electricity, you may 
use Equation 2 of this section as an alternative to using Equation 1 of 
this section to demonstrate that the PM, HF, HCl, non-Hg HAP metals, 
and Hg emissions from all existing units participating in the emissions 
averaging option do not exceed the emission limits in Table 2 to this 
subpart.
[GRAPHIC] [TIFF OMITTED] TP03MY11.016

Where:

Ave Weighted Emissions = Average weighted emission level for PM, HF, 
HCl, non-Hg HAP metals, or Hg, in units of lb/MMBtu (lb/TBtu for Hg) 
of heat input.
Er = Emissions rate (as determined during the most recent 
performance test, according to Table 5 to this subpart) for PM, HF, 
HCl, non-Hg HAP metals, or Hg or by fuel analysis for Cl, F, non-Hg 
HAP metals, or Hg as calculated by the applicable equation in Sec.  
63.10011(c)) for unit, i, for PM, HCl, HF, HAP metals, or Hg, in 
units of lb/MMBtu (lb/TBtu for Hg) of heat input.
Sm = Maximum steam generation by unit, i, in units of pounds.
Cf = Conversion factor, calculated from the most recent compliance 
test, in units of million Btu of heat input per pounds of steam 
generated for unit, i.
n = Number of units participating in the emissions averaging option.

    (f) You must demonstrate compliance on a monthly basis determined 
at the end of every month (12 times per year) according to paragraphs 
(f)(1) through (3) of this section. The first monthly period begins on 
the compliance date specified in Sec.  63.9984.
    (1) For each calendar month, you must use Equation 3 of this 
section to calculate the monthly average weighted emission rate using 
the actual heat capacity for each existing unit participating in the 
emissions averaging option.
[GRAPHIC] [TIFF OMITTED] TP03MY11.017

Where:

Ave Weighted Emissions = Monthly average weighted emission level for 
PM, HCl, HF, non-Hg HAP metals, or Hg, in units of lb/MMBtu (lb/TBtu 
for Hg) of heat input.
Er = Emissions rate, (as determined during the most recent 
performance test, according to Table 5 to this subpart) for PM, HCl, 
HF, non-Hg HAP metals, or Hg or by fuel analysis for Cl, F, non-Hg 
HAP metals, or Hg as calculated by the applicable equation in Sec.  
63.10011(c)) for unit, i, for PM, HCl, HF, non-Hg HAP metals, or Hg, 
in units of lb/MMBtu (lb/TBtu for Hg) of heat input.
Hb = The average heat input for each calendar month of EGU, i, in 
units of million Btu.
n = Number of units participating in the emissions averaging option.
    (2) If you are not capable of monitoring heat input, you may use 
Equation 4 of this section as an alternative to using Equation 3 of 
this section to calculate the monthly weighted emission rate using the 
actual steam generation from the units participating in the emissions 
averaging option.
[GRAPHIC] [TIFF OMITTED] TP03MY11.018

Where:

Ave Weighted Emissions = Monthly average weighted emission level for 
PM, HCl, HF, HAP metals, or Hg, in units of lb/MMBtu (lb/TBtu for 
Hg) of heat input.
Er = Emissions rate, (as determined during the most recent 
performance test, as calculated according to Table 5 to this 
subpart) for PM, HCl, HF, non-Hg HAP metals, or Hg or by fuel 
analysis for Cl, F, and non-Hg HAP metals, or Hg as calculated by 
the applicable equation in Sec.  63.10011(c)) for unit, i, for PM, 
HCl, HF, non-Hg HAP metals, or Hg, in units of lb/MMBtu (lb/TBtu for 
Hg) of heat input.
Sa = Actual steam generation for each calendar month by EGU, i, in 
units of pounds.
Cf = Conversion factor, as calculated during the most recent 
compliance test, in units of million Btu of heat input per pounds of 
steam generated for unit, i.
n = Number of units participating in the emissions averaging option.

    (3) Until 12 monthly weighted average emission rates have been 
accumulated, calculate and report only the monthly

[[Page 25110]]

average weighted emission rate determined under paragraph (f)(1) or (2) 
of this section. After 12 monthly weighted average emission rates have 
been accumulated, for each subsequent calendar month, use Equation 5 of 
this section to calculate the 12-month rolling average of the monthly 
weighted average emission rates for the current month and the previous 
11 months.
[GRAPHIC] [TIFF OMITTED] TP03MY11.019

Where:

Eavg = 12-month rolling average emissions rate, (lb/MMBtu heat 
input; lb/TBtu for Hg).
ERi = Monthly weighted average, for month ``i'' (lb/MMBtu (lb/TBtu 
for Hg) heat input)(as calculated by (f)(1) or (2)).

    (g) You must develop, and submit to the applicable regulatory 
authority for review and approval upon request, an implementation plan 
for emission averaging according to the following procedures and 
requirements in paragraphs (g)(1) through (4) of this section.
    (1) You must submit the implementation plan no later than 180 days 
before the date that the facility intends to demonstrate compliance 
using the emission averaging option.
    (2) You must include the information contained in paragraphs 
(g)(2)(i) through (vii) of this section in your implementation plan for 
all emission sources included in an emissions average:
    (i) The identification of all existing EGUs in the averaging group, 
including for each either the applicable HAP emission level or the 
control technology installed as of [DATE 60 DAYS AFTER PUBLICATION OF 
THE FINAL RULE IN THE FEDERAL REGISTER] and the date on which you are 
requesting emission averaging to commence;
    (ii) The process parameter (heat input 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 emissions from multiple EGUs, the owner 
or operator must identify each EGU;
    (iv) The test plan for the measurement of PM, HF, HCl, individual 
or total non-Hg HAP metals, or Hg emissions in accordance with the 
requirements in Sec.  63.10007;
    (v) The operating parameters to be monitored for each control 
system or device consistent with Sec.  63.9991 and Table 4, and a 
description of how the operating limits will be determined;
    (vi) If you request to monitor an alternative operating parameter 
pursuant to Sec.  63.10010, you must also include:
    (A) A description of the parameter(s) to be monitored and an 
explanation of the criteria used to select the parameter(s); and
    (B) A description of the methods and procedures that will be used 
to demonstrate that the parameter indicates proper operation of the 
control device; the frequency and content of monitoring, reporting, and 
recordkeeping requirements; and a demonstration, to the satisfaction of 
the applicable regulatory authority, that the proposed monitoring 
frequency is sufficient to represent control device operating 
conditions; and
    (vii) A demonstration that compliance with each of the applicable 
emission limit(s) will be achieved under representative operating 
conditions.
    (3) The regulatory authority shall review and approve or disapprove 
the plan according to the following criteria:
    (i) Whether the content of the plan includes all of the information 
specified in paragraph (g)(2) of this section; and
    (ii) Whether the plan presents sufficient information to determine 
that compliance will be achieved and maintained.
    (4) The applicable regulatory authority shall not approve an 
emission averaging implementation plan containing any of the following 
provisions:
    (i) Any averaging between emissions of differing pollutants or 
between differing sources; or
    (ii) The inclusion of any emission source other than an existing 
unit in the same subcategory.
    (h) 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 PM, HF, HCl, individual or total 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 paragraph (i) or (j) of this 
section.
    (i) For a group of two or more existing units in the same 
subcategory, each of which vents 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.
    (j) For all other groups of units subject to paragraph (h) of this 
section, the owner or operator may elect to:
    (1) Conduct performance tests according to procedures specified in 
Sec.  63.10007 in the common stack if affected units from other 
subcategories vent to the common stack. The emission limits that the 
group must comply with are determined by the use of equation 6.
[GRAPHIC] [TIFF OMITTED] TP03MY11.020

Where:

En = HAP emissions limit, lb/MMBtu (lb/TBtu for Hg), ppm, or ng/
dscm.
ELi = Appropriate emissions limit from Table 2 to this subpart for 
unit i, in units of lb/MMBtu (lb/TBtu for Hg), ppm, or ng/dscm.
Hi = Heat input from unit i, MMBtu.
n = Number of units.

    (2) Conduct performance tests according to procedures specified in 
Sec.  63.10007 in the common stack. If affected units from nonaffected 
units vent to the common stack,the units from nonaffected units must be 
shut down or vented to a different stack during the performance test or 
each affected and each nonaffected unit must meet the most stringent 
emissions limit; and
    (3) Meet the applicable operating limit specified in Sec.  63.10021 
and Table 8 to this subpart for each emissions control system (except 
that, if each unit venting to the common stack has an applicable 
opacity operating limit, then a single continuous opacity monitoring 
system may be located in the common stack instead of in each duct to 
the common stack).
    (k) Combination requirements. The common stack of a group of two or 
more existing EGUs in the same subcategory subject to paragraph (h) of 
this section may be treated as a single stack for purposes of paragraph 
(b) of this section and included in an emissions averaging group 
subject to paragraph (b) of this section.


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

    (a) In some cases, existing affected units may exhaust through a 
common stack configuration or may include a bypass stack. Emission 
monitoring system installation provisions for possible stack 
configurations are as follows.
    (1) Single Unit-Single Stack Configuration. For an affected unit 
that exhausts to the atmosphere through a single, dedicated stack, the 
owner or operator shall install CEMS and sorbent trap monitoring 
systems in accordance

[[Page 25111]]

with the applicable performance specification or Appendix A to this 
subpart.
    (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, the owner or operator shall 
either:
    (i) Install CEMS and sorbent trap monitoring systems described in 
this section in the duct to the common stack from each unit; or
    (ii) Install CEMS and sorbent trap monitoring systems described in 
this section in the common stack.
    (3) Unit Utilizing Common Stack with Non-affected Units. When one 
or more affected units shares a common stack with one or more non-
affected units, the owner or operator shall either:
    (i) Install CEMS and sorbent trap monitoring systems described in 
this section in the duct to the common stack from each affected unit; 
or
    (ii) Install CEMS 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).
    (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, the owner and operator shall install CEMS and the monitoring 
systems described in paragraph 2.1 of this section on both the main 
stack and the bypass stack.
    (5) Unit with Multiple Stack or Duct Configuration. If the flue 
gases from an affected unit either: are discharged to the atmosphere 
through more than one stack; or are fed into a single stack through two 
or more ducts and the owner or operator chooses to monitor in the ducts 
rather than in the stack, the owner or operator shall either:
    (i) Install CEMS and sorbent trap monitoring systems described in 
this section in each of the multiple stacks; or
    (ii) Install CEMS and sorbent trap monitoring systems described in 
this section in each of the ducts that feed into the stack.
    (b) If you use an oxygen (O2) or carbon dioxide 
(CO2) continuous emissions monitoring system (CEMS), 
install, operate, and maintain a CEMS for oxygen or carbon dioxide 
according to the procedures in paragraphs (b)(1) through (5) of this 
section by the compliance date specified in Sec.  63.9984. The oxygen 
or carbon dioxide shall be monitored at the same location as the other 
pollutant CEMS, i.e., at the outlet of the EGU. Alternatively, an owner 
or operator may install, certify, maintain, operate and quality assure 
the data from an O2 or CO2 CEMS according to 
Appendix A of this subpart in lieu of the procedures in paragraphs 
(a)(1) through (a)(3) of this section.
    (1) Install, operate, and maintain the O2 or 
CO2 CEMS according to the applicable procedures under 
Performance Specification (PS) 3 of 40 CFR part 60, Appendix B; and 
according to the applicable procedures under Quality Assurance 
Procedure 1 of 40 CFR part 60, Appendix F; and according to the site-
specific monitoring plan developed according to Sec.  63.10000(d).
    (2) Conduct a performance evaluation of the CEMS according to the 
requirements in Sec.  63.8 and according to PS 3 of 40 CFR part 60, 
Appendix B.
    (3) Design and operate the CEMS to complete a minimum of one cycle 
of operation (sampling, analyzing, and data recording) for each 
successive 15-minute period.
    (4) Reduce the CEMS data as specified in Sec.  63.8(g)(2) and (4).
    (5) Consistent with Sec.  63.10020, calculate and record a 30 
boiler operating day rolling average emissions rate on a daily basis. 
Daily, calculate a new 30 boiler operating day rolling average 
emissions rate as the average of all of the hourly oxygen emissions 
data for the preceding 30 boiler operating days.
    (c) If you use an HCl CEMS, install, operate, and maintain a CEMS 
for HCl according to the procedures in paragraphs (c)(1) through (5) of 
this section by the compliance date specified in Sec.  63.9984. The HCl 
shall be monitored at the outlet of the EGU.
    (1) Install, operate, and maintain the CEMS according to the 
applicable procedures under Performance Specification (PS) 15 or 6 of 
40 CFR part 60, Appendix B; and according to the applicable procedures 
under Quality Assurance Procedure 1 of 40 CFR part 60, Appendix F; and 
according to the site-specific monitoring plan developed according to 
Sec.  63.10000(d).
    (2) Conduct a performance evaluation of the CEMS according to the 
requirements in Sec.  63.8 and according to PS 15 or 6 of 40 CFR part 
60, Appendix B.
    (3) Design and operate the CEMS to complete a minimum of one cycle 
of operation (sampling, analyzing, and data recording) for each 
successive 15-minute period.
    (4) Reduce the CEMS data as specified in Sec.  63.8(g)(2) and (4).
    (5) Consistent with Sec.  63.10020, calculate and record a 30 
boiler operating day rolling average emissions rate on a daily basis. 
Daily, calculate a new 30 boiler operating day rolling average 
emissions rate as the average of all of the hourly HCl emissions data 
for the preceding 30 boiler operating days.
    (d) If you use an HF CEMS, install, operate, and maintain a CEMS 
for HF according to the procedures in paragraphs (d)(1) through (5) of 
this section by the compliance date specified in Sec.  63.9984. The HF 
shall be monitored at the outlet of the EGU.
    (1) Install, operate, and maintain the CEMS according to the 
applicable procedures under Performance Specification (PS) 15 of 40 CFR 
part 60, Appendix B; and according to the applicable procedures under 
Quality Assurance Procedure 1 of 40 CFR part 60, Appendix F; and 
according to the site-specific monitoring plan developed according to 
Sec.  63.10000(d).
    (2) Conduct a performance evaluation of the CEMS according to the 
requirements in Sec.  63.8 and according to PS 15 or 6 of 40 CFR part 
60, Appendix B.
    (3) Design and operate the CEMS to complete a minimum of one cycle 
of operation (sampling, analyzing, and data recording) for each 
successive 15-minute period.
    (4) Reduce the CEMS data as specified in Sec.  63.8(g)(2) and (4).
    (5) Consistent with Sec.  63.10020, calculate and record a 30 
boiler operating day rolling average emissions rate on a daily basis. 
Daily, calculate a new 30 boiler operating day rolling average 
emissions rate as the average of all of the hourly HF emissions data 
for the preceding 30 boiler operating days.
    (e) If you use an SO2 CEMS, install, operate, and 
maintain a CEMS for SO2 according to the procedures in 
paragraphs (e)(1) through (5) of this section by the compliance date 
specified in Sec.  63.9984. The SO2 shall be monitored at 
the outlet of the EGU. Alternatively, for an affected source that is 
also subject to the SO2 monitoring requirements of Part 75 
of this chapter, the or operator may install, certify, maintain, 
operate and quality assure the data from an SO2 CEMS 
according to Part 75 of this chapter in lieu of the procedures in 
paragraphs (g)(1) through (g)(3) of this section with the additional 
provisions of paragraph (g)(6).
    (1) Install, operate, and maintain the CEMS according to the 
applicable procedures under Performance Specification (PS) 2 of 40 CFR 
part 60, Appendix B; and according to the applicable procedures under 
Quality Assurance Procedure 1 of 40 CFR part 60, Appendix F; and 
according to the site-specific monitoring plan developed according to 
Sec.  63.10000(d).
    (2) Conduct a performance evaluation of the CEMS according to the

[[Page 25112]]

requirements in Sec.  63.8 and according to PS 2 or 6 of 40 CFR part 
60, Appendix B.
    (3) Design and operate the CEMS to complete a minimum of one cycle 
of operation (sampling, analyzing, and data recording) for each 
successive 15-minute period.
    (4) Reduce the CEMS data as specified in Sec.  63.8(g)(2) and (4).
    (5) Consistent with Sec.  63.10020, calculate and record a 30 
boiler operating day rolling average emissions rate on a daily basis. 
Daily, calculate a new 30 boiler operating day rolling average 
emissions rate is calculated as the average of all of the hourly 
SO2 emissions data for the preceding 30 boiler operating 
days.
    (6) When electing to use a Part 75 certified SO2 CEMS to 
meet the requirements of this subpart, you must additionally meet the 
provisions listed in paragraphs (6)(i) through (6)(iii) below.
    (i) You must perform the 7-day calibration error test required in 
appendix A to Part 75 on the SO2 CEMS whether or not it has 
a span of 50 ppm or less.
    (ii) You must perform the linearity check test required in appendix 
A to Part 75 on the SO2 CEMS whether or not it has a span of 
30 ppm or less.
    (iii) The initial and quarterly linearity checks required under 
appendix A and appendix B of Part 75 must include a calibration gas (at 
a fourth level, if necessary) nominally at a concentration level 
equivalent to the applicable emission limit.
    (f) If you use a Hg CEMS or a sorbent trap monitoring system for 
Hg, install, operate, and maintain the monitoring system in accordance 
with Appendix A to this subpart.
    (g) If you use a PM CEMS, install, operate, and maintain a CEMS for 
PM according to the procedures in paragraphs (g)(1) through (6) of this 
section by the compliance date specified in Sec.  63.9984. The PM shall 
be monitored at the outlet of the EGU.
    (1) Install, operate, and maintain according to the applicable 
procedures under Performance Specification (PS) 11 of 40 CFR part 60, 
Appendix B; and according to the applicable procedures under Quality 
Assurance Procedure 2 of 40 CFR part 60, Appendix F; and according to 
the site-specific monitoring plan developed according to Sec.  
63.10000(d).
    (2) Conduct a performance evaluation of the CEMS according to the 
requirements in Sec.  63.8 and according to PS 11 of 40 CFR part 60, 
Appendix B.
    (3) Design and operate the CEMS to complete a minimum of one cycle 
of operation (sampling, analyzing, and data recording) for each 
successive 15-minute period.
    (4) Reduce the CEMS data as specified in Sec.  63.8(g)(2) and (4).
    (5) Consistent with Sec.  63.10020, calculate and record a 30 
boiler operating-day rolling average emissions rate on a daily basis. 
Daily, calculate a new 30 boiler operating day rolling average 
emissions rate is calculated as the average of all of the hourly 
particulate emissions data for the preceding 30 boiler operating days.
    (h) If you are required to install a continuous parameter 
monitoring system (CPMS) as specified in Table 5 of this subpart, you 
must install, operate, and maintain each CPMS according to the 
requirements in paragraphs (h)(1) through (3) of this section by the 
compliance date specified in Sec.  63.9984.
    (1) Install, operate, and maintain each CPMS according to the 
procedures in your approved site-specific monitoring plan developed in 
accordance with Sec.  63.10000(d) of this subpart and the design 
criteria and quality assurance and quality control procedures specified 
in paragraphs (h)(1) through (3) of this section. You may request 
approval of monitoring system quality assurance and quality control 
procedures alternative to those specified in paragraphs (h)(1) through 
(3) of this section in your site-specific monitoring plan.
    (2) Design and operate the CPMS to collect and record data 
measurements at least once every 15 minutes (see also Sec.  63.10020), 
to reduce the measured values to a hourly averages or other appropriate 
period (e.g., instantaneous alarms) for calculating operating values in 
terms of the applicable averaging period, and to meet the specific CPMS 
requirements given in (i) through (v) of this section.
    (i) If you have an operating limit that requires the use of a flow 
monitoring system, you must meet the requirements in (i)(A) through (D) 
of this section.
    (A) Install the flow sensor and other necessary equipment in a 
position that provides a representative flow.
    (B) Use a flow sensor with a measurement sensitivity of no greater 
than 2 percent of the expected flow rate.
    (C) Minimize the effects of swirling flow or abnormal velocity 
distributions due to upstream and downstream disturbances.
    (D) Conduct a flow monitoring system performance evaluation in 
accordance with your monitoring plan at the time of each performance 
test but no less frequently than annually.
    (ii) If you have an operating limit that requires the use of a 
pressure monitoring system, you must meet the requirements in (ii)(A) 
through (F) of this section.
    (A) Install the pressure sensor(s) in a position that provides a 
representative measurement of the pressure (e.g., PM scrubber pressure 
drop).
    (B) Minimize or eliminate pulsating pressure, vibration, and 
internal and external corrosion.
    (C) Use a pressure sensor with a minimum tolerance of 1.27 
centimeters of water or a minimum tolerance of 1 percent of the 
pressure monitoring system operating range, whichever is less.
    (D) Perform checks at least once each boiler operating day to 
ensure pressure measurements are not obstructed (e.g., check for 
pressure tap pluggage daily).
    (E) Conduct a performance evaluation of the pressure measurement 
monitoring system in accordance with your monitoring plan at the time 
of each performance test but no less frequently than annually.
    (F) If at any time the measured pressure exceeds the manufacturer's 
specified maximum operating pressure range, conduct a performance 
evaluation of the pressure monitoring system in accordance with your 
monitoring plan and confirm that the pressure monitoring system 
continues to meet the performance requirements in your monitoring plan. 
Alternatively, install and verify the operation of a new pressure 
sensor.
    (iii) If you have an operating limit that requires a total 
secondary electric power monitoring system for an electrostatic 
precipitator (ESP), you must meet the requirements in (iii)(A) through 
(B) of this section.
    (A) Install sensors to measure (secondary) voltage and current to 
the precipitator plates.
    (B) Conduct a performance evaluation of the electric power 
monitoring system in accordance with your monitoring plan at the time 
of each performance test but no less frequently than annually.
    (iv) If you have an operating limit that requires the use of a 
monitoring system to measure sorbent injection rate (e.g., weigh belt, 
weigh hopper, or hopper flow measurement device), you must meet the 
requirements in (iv)(A) through (B) of this section.
    (A) Install each system in a position that provides a 
representative measurement of the total sorbent injection rate.
    (B) Conduct a performance evaluation of the sorbent injection rate 
monitoring system in accordance with your

[[Page 25113]]

monitoring plan at the time of each performance test but no less 
frequently than annually.
    (v) If you have an operating limit that requires the use of a 
fabric filter bag leak detection system to comply with the requirements 
of this subpart, you must install, calibrate, maintain, and 
continuously operate a bag leak detection system as specified in (v)(A) 
through (F) of this section.
    (A) Install a bag leak detection sensor(s) in a position(s) that 
will be representative of the relative or absolute PM loadings for each 
exhaust stack, roof vent, or compartment (e.g., for a positive pressure 
fabric filter) of the fabric filter.
    (B) Use a bag leak detection system certified by the manufacturer 
to be capable of detecting PM emissions at concentrations of 10 
milligrams per actual cubic meter or less.
    (C) Conduct a performance evaluation of the bag leak detection 
system in accordance with your monitoring plan and consistent with the 
guidance provided in EPA-454/R-98-015 (incorporated by reference, see 
Sec.  63.14).
    (D) Use a bag leak detection system equipped with a device to 
continuously record the output signal from the sensor.
    (E) Use a bag leak detection system equipped with a system that 
will alert when an increase in relative PM emissions over a preset 
level is detected. The alarm must be located where it can be detected 
and recognized easily by an operator.
    (F) Where multiple bag leak detectors are required, the system's 
instrumentation and alarm may be shared among detectors.
    (3) Conduct the CPMS equipment performance evaluations as specified 
in your site-specific monitoring plan.


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

    (a) You must demonstrate initial compliance with each emission 
limit that applies to you by conducting initial performance tests and 
fuel analyses and establishing operating limits, as applicable, 
according to Sec.  63.10007, paragraph (c) of this section, and Tables 
5 and 7 to this subpart.
    (b) If you demonstrate compliance through performance testing, you 
must establish each site-specific operating limit in Table 4 to this 
subpart that applies to you according to the requirements in Sec.  
63.10007, Table 7 to this subpart, and paragraph (c)(6) of this 
section, as applicable. You must also conduct fuel analyses according 
to Sec.  63.10008 and establish maximum fuel pollutant input levels 
according to paragraphs (c)(1) through (5) of this section, as 
applicable.
    (1) You must establish the maximum chlorine fuel input 
(Cinput) during the initial performance testing according to 
the procedures in paragraphs (c)(1)(i) through (iii) of this section.
    (i) You must determine the fuel type or fuel mixture that you could 
burn in your EGU that has the highest content of chlorine.
    (ii) During the performance testing for HCl, you must determine the 
fraction of the total heat input for each fuel type burned 
(Qi) based on the fuel mixture that has the highest content 
of chlorine, and the average chlorine concentration of each fuel type 
burned (Ci).
    (iii) You must establish a maximum chlorine input level using 
Equation 7 of this section.
[GRAPHIC] [TIFF OMITTED] TP03MY11.021

Where:

Clinput = Maximum amount of chlorine entering the EGU through fuels 
burned in units of lb/MMBtu.
Ci = Arithmetic average concentration of chlorine in fuel type, i, 
analyzed according to Sec.  63.10008, in units of lb/MMBtu.
Qi = Fraction of total heat input from fuel type, i, based on the 
fuel mixture that has the highest content of chlorine. If you do not 
burn multiple fuel types during the performance testing, it is not 
necessary to determine the value of this term. Insert a value of 
``1'' for Qi.
n = Number of different fuel types burned in your EGU for the 
mixture that has the highest content of chlorine.

    (2) You must establish the maximum Hg fuel input level 
(Mercuryinput) during the initial performance testing using 
the procedures in paragraphs (c)(3)(i) through (iii) of this section.
    (i) You must determine the fuel type or fuel mixture that you could 
burn in your EGU that has the highest content of Hg.
    (ii) During the compliance demonstration for Hg, you must determine 
the fraction of total heat input for each fuel burned (Qi) 
based on the fuel mixture that has the highest content of Hg, and the 
average Hg concentration of each fuel type burned (HGi).
    (iii) You must establish a maximum Hg input level using Equation 8 
of this section.
[GRAPHIC] [TIFF OMITTED] TP03MY11.022

Where:

Mercuryinput = Maximum amount of Hg entering the EGU through fuels 
burned in units of lb/TBtu.
HGi = Arithmetic average concentration of Hg in fuel type, i, 
analyzed according to Sec.  63.10008, in units of lb/TBtu.
Qi = Fraction of total heat input from fuel type, i, based on the 
fuel mixture that has the highest Hg content. If you do not burn 
multiple fuel types during the performance test, it is not necessary 
to determine the value of this term. Insert a value of ``1'' for Qi.
n = Number of different fuel types burned in your EGU for the 
mixture that has the highest content of Hg.

    (3) You must establish the maximum non-Hg HAP metals fuel input 
level (HAP metalinput) during the initial performance 
testing using the procedures in paragraphs (c)(3)(i) through (iii) of 
this section.
    (i) You must determine the fuel type or fuel mixture that you could 
burn in your EGU that has the highest content of non-Hg HAP metals.
    (ii) During the compliance demonstration for non-Hg HAP metals, you 
must determine the fraction of total heat input for each fuel burned 
(Qi) based on the fuel mixture that has the highest content 
of non-Hg HAP metals, and the average non-Hg HAP metals concentration 
of each fuel type burned (HAP metali).
    (iii) You must establish a maximum non-Hg HAP metal input level 
using Equation 9 of this section.
[GRAPHIC] [TIFF OMITTED] TP03MY11.023

Where:

HAP metalinput = Maximum amount of non-Hg HAP metals entering the 
EGU through fuels burned in units of lb/MMBtu.
HAP metali = Arithmetic average concentration of non-Hg HAP metals 
in fuel type, i, analyzed according to Sec.  63.10008, in units of 
lb/MMBtu.
Qi = Fraction of total heat input from fuel type, i, based on the 
fuel mixture that

[[Page 25114]]

has the highest non-Hg HAP metal content. If you do not burn 
multiple fuel types during the performance test, it is not necessary 
to determine the value of this term. Insert a value of ``1'' for Qi.
n = Number of different fuel types burned in your EGU for the 
mixture that has the highest content of non-Hg HAP metals.

    (4) You must establish the maximum fluorine fuel input 
(Finput) during the initial performance testing according to 
the procedures in paragraphs (c)(1)(i) through (iii) of this section.
    (i) You must determine the fuel type or fuel mixture that you could 
burn in your EGU that has the highest content of fluorine.
    (ii) During the performance testing for HF, you must determine the 
fraction of the total heat input for each fuel type burned 
(Qi) based on the fuel mixture that has the highest content 
of fluorine, and the average fluorine concentration of each fuel type 
burned (Fi).
    (iii) You must establish a maximum fluorine input level using 
Equation 10 of this section.
[GRAPHIC] [TIFF OMITTED] TP03MY11.024

Where:

Fl input = Maximum amount of fluorine entering the EGU through fuels 
burned in units of lb/MMBtu.
Fi = Arithmetic average concentration of fluorine in fuel type, i, 
analyzed according to Sec.  63.10008, in units of lb/MMBtu.
Qi = Fraction of total heat input from fuel type, i, based on the 
fuel mixture that has the highest content of chlorine. If you do not 
burn multiple fuel types during the performance testing, it is not 
necessary to determine the value of this term. Insert a value of 
``1'' for Qi.
n = Number of different fuel types burned in your EGU for the 
mixture that has the highest content of fluorine.

    (6) You must establish parameter operating limits according to 
paragraphs (c)(4)(i) through (v) of this section.
    (i) For a wet PM scrubber, you must establish the minimum liquid 
flow rate and pressure drop as defined in Sec.  63.10042, as your 
operating limits during the three-run performance test. If you use a 
wet PM scrubber and you conduct separate performance tests for PM, non-
Hg HAP metals, or Hg emissions, you must establish one set of minimum 
liquid flow rate and pressure drop operating limits. If you conduct 
multiple performance tests, you must set the minimum liquid flow rate 
and pressure drop operating limits at the highest minimum hourly 
average values established during the performance tests.
    (ii) For a wet acid gas scrubber, you must establish the minimum 
liquid flow rate and pH as defined in Sec.  63.10042, as your operating 
limits during the three-run performance test. If you use a wet acid gas 
scrubber and you conduct separate performance tests for HCl, HF, or 
SO2 emissions, you must establish one set of minimum liquid 
flow rate and pH operating limits. If you conduct multiple performance 
tests, you must set the minimum liquid flow rate and pH operating 
limits at the highest minimum hourly average values established during 
the performance tests.
    (iii) For an electrostatic precipitator, you must establish the 
minimum hourly average secondary voltage and secondary amperage and 
calculate the total secondary power input as measured during the three-
run performance test and as defined in Sec.  63.10042, as your 
operating limit.
    (iv) For a dry scrubber or dry sorbent injection (DSI) system, you 
must establish the minimum hourly average sorbent injection rate for 
each sorbent, as measured during the three-run performance test and as 
defined in Sec.  63.10042, as your operating.
    (v) The operating limit for EGUs with fabric filters that choose to 
demonstrate continuous compliance through bag leak detection systems is 
that a bag leak detection system be installed according to the 
requirements in Sec.  63.10010, and that the sum duration of bag leak 
detection system alarms does not exceed 5 percent of the process 
operating time during a 6-month period.
    (c) If you elect to demonstrate compliance with an applicable 
emission limit through fuel analysis, you must conduct fuel analyses 
according to Sec.  63.10008 and follow the procedures in paragraphs 
(c)(1) through (7) of this section.
    (1) If you burn more than one fuel type, you must determine the 
fuel mixture you could burn in your EGU that would result in the 
maximum emission rates of the pollutants that you elect to demonstrate 
compliance through fuel analysis.
    (2) You must determine the 90th percentile confidence level fuel 
pollutant concentration of the composite samples analyzed for each fuel 
type using the one-sided z-statistic test described in Equation 11 of 
this section.
[GRAPHIC] [TIFF OMITTED] TP03MY11.025

Where:

P90 = 90th percentile confidence level pollutant concentration, in 
lb/MMBtu (lb/TBtu for Hg).
mean = Arithmetic average of the fuel pollutant concentration in the 
fuel samples analyzed according to Sec.  63.10008, in units of lb/
MMBtu (lb/TBtu for Hg).
SD = Standard deviation of the pollutant concentration in the fuel 
samples analyzed according to Sec.  63.10008, in units of lb/MMBtu 
(lb/TBtu for Hg).
t = t distribution critical value for 90th percentile (0.1) 
probability for the appropriate degrees of freedom (number of 
samples minus one) as obtained from a Distribution Critical Value 
Table.

    (3) To demonstrate compliance with the applicable emission limit 
for HCl, the HCl emission rate that you calculate for your EGU using 
Equation 12 of this section must not exceed the applicable emission 
limit for HCl.
[GRAPHIC] [TIFF OMITTED] TP03MY11.026

Where:

HCl = HCl emissions rate from the EGU in units of lb/MMBtu.
Ci90 = 90th percentile confidence level concentration of chlorine in 
fuel type, i, in units of lb/MMBtu as calculated according to 
Equation 12 of this section.
Qi = Fraction of total heat input from fuel type, i, based on the 
fuel mixture that has the highest content of chlorine. If you do not 
burn multiple fuel types, it is not necessary to determine the value 
of this term. Insert a value of ``1'' for Qi.
n = Number of different fuel types burned in your EGU for the 
mixture that has the highest content of chlorine.
1.028 = Molecular weight ratio of HCl to chlorine.

    \(4) To demonstrate compliance with the applicable emission limit 
for Hg, the Hg emissions rate that you calculate for your EGU using 
Equation 13 of this section must not exceed the applicable emission 
limit for Hg.
[GRAPHIC] [TIFF OMITTED] TP03MY11.027

Where:

Mercury = Hg emissions rate from the EGU in units of lb/TBtu.
HGi90 = 90th percentile confidence level concentration of Hg in 
fuel, i, in units of lb/TBtu as calculated according to Equation 8 
of this section.
Qi = Fraction of total heat input from fuel type, i, based on the 
fuel mixture that has the highest Hg content. If you do not burn 
multiple fuel types, it is not necessary to determine the value of 
this term. Insert a value of ``1'' for Qi.
n = Number of different fuel types burned in your EGU for the 
mixture that has the highest Hg content.

    (5) To demonstrate compliance with the applicable emission limit 
for non-Hg HAP metals, the non-Hg HAP metal emissions rate that you 
calculate for your EGU using Equation 14 of this

[[Page 25115]]

section must not exceed the applicable emissions limit for non-Hg HAP 
metals.
[GRAPHIC] [TIFF OMITTED] TP03MY11.028

Where:

HAPmetals = Non-Hg HAP metals emission rate from the EGU in units of 
lb/MMBtu.
HAPmetalsi90 = 90th percentile confidence level concentration of 
non-Hg HAP metals in fuel, i, in units of lb/MMBtu as calculated 
according to Equation 9 of this section.
Qi = Fraction of total heat input from fuel type, i, based on the 
fuel mixture that has the highest non-Hg HAP metals content. If you 
do not burn multiple fuel types, it is not necessary to determine 
the value of this term. Insert a value of ``1'' for Qi.
n = Number of different fuel types burned in your EGU for the 
mixture that has the highest non-Hg HAP metals content.

    (6) To demonstrate compliance with the applicable emission limit 
for HF, the HF emissions rate that you calculate for your EGU using 
Equation 15 of this section must not exceed the applicable emission 
limit for HF.
[GRAPHIC] [TIFF OMITTED] TP03MY11.029

Where:

HF = HF emissions rate from the EGU in units of lb/MMBtu.
Fi90 = 90th percentile confidence level concentration of fluorine in 
fuel type, i, in units of lb/MMBtu as calculated according to 
Equation 7 of this section.
Qi = Fraction of total heat input from fuel type, i, based on the 
fuel mixture that has the highest content of fluorine. If you do not 
burn multiple fuel types, it is not necessary to determine the value 
of this term. Insert a value of ``1'' for Qi.
n = Number of different fuel types burned in your EGU for the 
mixture that has the highest content of fluorine.
1.053 = Molecular weight ratio of HF to fluorine.

    (d) For units combusting coal or solid oil-derived fuel and 
electing to use PM as a surrogate for non-Hg HAP metals, you must 
install, certify, and operate PM CEMS in accordance with Performance 
Specification (PS) 11 in Appendix B to 40 CFR part 60, and to perform 
periodic, ongoing quality assurance (QA) testing of the CEMS according 
to QA Procedure 2 in Appendix F to 40 CFR Part 60. You must determine 
an operating limit (PM concentration in mg/dscm) during performance 
testing for initial PM compliance. The operating limit will be the 
average of the PM filterable results of the three Method 5 performance 
test runs. To determine continuous compliance, the hourly average PM 
concentrations will be averaged on a rolling 30 boiler operating day 
basis. Each 30 boiler operating day average would have to meet the PM 
operating limit.
    (e) You must submit the Notification of Compliance Status 
containing the results of the initial compliance demonstration 
according to the requirements in Sec.  63.10030(e).
    (f) If you are a LEE, the results of your initial performance test 
demonstrate your initial compliance.

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. 
A monitoring system malfunction is 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. 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 monitoring system 
malfunctions or out-of-control periods, repairs associated with 
monitoring system malfunctions or 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 out-of-
control periods, repairs associated with monitoring system malfunctions 
or 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 and work practice standards?

    (a) You must demonstrate continuous compliance with each emission 
limit, operating limit, and work practice standard in Tables 1 through 
4 to this subpart that applies to you according to the methods 
specified in Table 8 to this subpart and paragraphs (a)(1) through (17) 
of this section.
    (1) Following the date on which the initial performance test is 
completed or is required to be completed under Sec. Sec.  63.7 and 
63.10005, whichever date comes first, you must not operate above any of 
the applicable maximum operating limits or below any of the applicable 
minimum operating limits listed in Table 4 to this subpart at any time. 
Operation above the established maximum or below the established 
minimum operating limits shall constitute a deviation of established 
operating limits. Operating limits must be confirmed or reestablished 
during performance tests.
    (2) As specified in Sec.  63.10031(c), you must keep records of the 
type and amount of all fuels burned in each EGU during the reporting 
period to demonstrate that all fuel types and mixtures of fuels burned 
would either result in lower emissions of HCl, HF, SO2, non-
Hg HAP metals, or Hg, than the applicable emission limit for each 
pollutant (if you demonstrate compliance through fuel analysis), or 
result in lower fuel input of chlorine, fluorine, sulfur, non-Hg HAP 
metals, or Hg than the maximum values calculated during the last 
performance tests (if you demonstrate compliance through performance 
stack testing).

[[Page 25116]]

    (3) If you demonstrate compliance with an applicable HCl emissions 
limit through fuel analysis and you plan to burn a new type of fuel, 
you must recalculate the HCl emissions rate using Equation 15 of Sec.  
63.10011 according to paragraphs (a)(3)(i) through (iii) of this 
section.
    (i) You must determine the chlorine concentration for any new fuel 
type in units of lb/MMBtu, based on supplier data or your own fuel 
analysis, according to the provisions in your site-specific fuel 
analysis plan developed according to Sec.  63.10008(b).
    (ii) You must determine the new mixture of fuels that will have the 
highest content of chlorine.
    (iii) Recalculate the HCl emissions rate from your EGU under these 
new conditions using Equation 15 of Sec.  63.10011. The recalculated 
HCl emissions rate must be less than the applicable emission limit.
    (4) If you demonstrate compliance with an applicable HCl emissions 
limit through performance testing and you plan to burn a new type of 
fuel or a new mixture of fuels, you must recalculate the maximum 
chlorine input using Equation 7 of Sec.  63.10011. If the results of 
recalculating the maximum chlorine input using Equation 7 of Sec.  
63.10011 are higher than the maximum chlorine input level established 
during the previous performance test, then you must conduct a new 
performance test within 60 days of burning the new fuel type or fuel 
mixture according to the procedures in Sec.  63.10007 to demonstrate 
that the HCl emissions do not exceed the emissions limit. You must also 
establish new operating limits based on this performance test according 
to the procedures in Sec.  63.10011(b).
    (5) If you are a liquid oil-fired EGU and demonstrate compliance 
with an applicable individual Hg emissions limit (rather than the total 
HAP metal emission limit) through fuel analysis, and you plan to burn a 
new type of fuel, you must recalculate the Hg emissions rate using 
Equation 11 of Sec.  63.10011 according to the procedures specified in 
paragraphs (a)(5)(i) through (iii) of this section.
    (i) You must determine the Hg concentration for any new fuel type 
in units of lb/TBtu, based on supplier data or your own fuel analysis, 
according to the provisions in your site-specific fuel analysis plan 
developed according to Sec.  63.10008(b).
    (ii) You must determine the new mixture of fuels that will have the 
highest content of Hg.
    (iii) Recalculate the Hg emissions rate from your EGU under these 
new conditions using Equation 11 of Sec.  63.10011. The recalculated Hg 
emission rate must be less than the applicable emission limit.
    (6) If you demonstrate compliance with an applicable Hg emissions 
limit through performance testing, and you plan to burn a new type of 
fuel or a new mixture of fuels, you must recalculate the maximum Hg 
input using Equation 8 of Sec.  63.10011. If the results of 
recalculating the maximum Hg input using Equation 8 of Sec.  63.10011 
are higher than the maximum Hg input level established during the 
previous performance test, then you must conduct a new performance test 
within 60 days of burning the new fuel type or fuel mixture according 
to the procedures in Sec.  63.10007 to demonstrate that the Hg 
emissions do not exceed the emissions limit. You must also establish 
new operating limits based on this performance test according to the 
procedures in Sec.  63.10011(b).
    (7) If you are a liquid oil-fired EGU and demonstrate compliance 
with an applicable HAP metals emission limit through fuel analysis, and 
you plan to burn a new type of fuel, you must recalculate the HAP 
metals emission rate using Equation 14 of Sec.  63.10011 according to 
the procedures specified in paragraphs (a)(7)(i) through (iii) of this 
section.
    (i) You must determine the HAP metals concentration for any new 
fuel type in units of lb/MMBtu, based on supplier data or your own fuel 
analysis, according to the provisions in your site-specific fuel 
analysis plan developed according to Sec.  63.10008(b).
    (ii) You must determine the new mixture of fuels that will have the 
highest content of HAP metals.
    (iii) Recalculate the HAP metals emission rate from your EGU under 
these new conditions using Equation 14 of Sec.  63.10011. The 
recalculated HAP metals emission rate must be less than the applicable 
emissions limit.
    (8) If you demonstrate compliance with an applicable HAP metals 
emissions limit through performance testing, and you plan to burn a new 
type of fuel or a new mixture of fuels, you must recalculate the 
maximum HAP metals input using Equation 9 of Sec.  63.10011. If the 
results of recalculating the maximum Hg input using Equation 9 of Sec.  
63.10011 are higher than the maximum HAP metals input level established 
during the previous performance test, then you must conduct a new 
performance test within 60 days of burning the new fuel type or fuel 
mixture according to the procedures in Sec.  63.10007 to demonstrate 
that the HAP metal emissions do not exceed the emissions limit. You 
must also establish new operating limits based on this performance test 
according to the procedures in Sec.  63.10011(b).
    (9) If your unit is controlled with a fabric filter, and you 
demonstrate continuous compliance using a bag leak detection system, 
you must initiate corrective action within 1 hour of a bag leak 
detection system alarm and complete corrective actions as soon as 
practical, and operate and maintain the fabric filter system such that 
the sum duration of alarms does not exceed 5 percent of the process 
operating time during a 6-month period. You must also keep records of 
the date, time, and duration of each alarm, the time corrective action 
was initiated and completed, and a brief description of the cause of 
the alarm and the corrective action taken. You must also record the 
percent of the operating time during each 6-month period that the alarm 
sounds. In calculating this operating time percentage, if inspection of 
the fabric filter demonstrates that no corrective action is required, 
no alarm time is counted. If corrective action is required, each alarm 
shall be counted as a minimum of 1 hour. If you take longer than 1 hour 
to initiate corrective action, the alarm time shall be counted as the 
actual amount of time taken to initiate corrective action.
    (10) If you are required to install a CEMS according to Sec.  
63.10010(a), then you must meet the requirements in paragraphs 
(a)(10)(i) through (iii) of this section.
    (i) You must continuously monitor oxygen according to Sec. Sec.  
63.10010(a) and 63.10020.
    (ii) Keep records of oxygen levels according to Sec.  63.10032(b).
    (11) The owner or operator of an affected source using a CEMS 
measuring PM emissions to meet requirements of this subpart shall 
install, certify, operate, and maintain the CEMS as specified in 
paragraphs (a)(11)(i) through (iv) of this section.
    (i) The owner or operator shall conduct a performance evaluation of 
the CEMS according to the applicable requirements of Sec.  60.13 of 40 
CFR, Performance Specification 11 in Appendix B of 40 CFR part 60, and 
procedure 2 in Appendix F of 40 CFR part 60.
    (ii) During each PM correlation testing run of the CEMS required by 
Performance Specification 11 in Appendix B of 40 CFR part 60, PM and 
O2 (or CO2) data shall be collected concurrently 
(or within a 30- to 60-minute period) by both the CEMS and conducting 
performance tests using

[[Page 25117]]

Method 5 or 5D of Appendix A-3 of 40 CFR part 60.
    (iii) Quarterly accuracy determinations and daily calibration drift 
tests shall be performed in accordance with procedure 2 in Appendix F 
of this chapter. Relative Response Audits must be performed annually 
and Response Correlation Audits must be performed every 3 years.
    (iv) As of January 1, 2012 and within 60 days after the date of 
completing each performance test, as defined in Sec.  63.2 and as 
required in this subpart, you must submit performance 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/). Only data collected using test methods 
compatible with ERT are subject to this requirement to be submitted 
electronically into EPA's WebFIRE database.
    (v) Within 60 days after the date of completing each CEMS 
performance evaluation test, as defined in Sec.  63.2 and required by 
this subpart, you must submit the relative accuracy test audit data 
electronically into EPA's Central Data Exchange by using the Electronic 
Reporting Tool as mentioned in paragraph (11)(iv) of this section. Only 
data collected using test methods compatible with ERT are subject to 
this requirement to be submitted electronically into EPA's WebFIRE 
database.
    (vi) All reports required by this subpart not subject to the 
requirements in paragraphs (11)(iv) and (v) 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 paragraph (11)(iv) and (v) of this section in paper 
format.
    (12) The owner or operator of an affected source using a CEMS 
measuring HCl emissions to meet requirements of this subpart shall 
install, certify, operate, and maintain the CEMS as specified in 
paragraphs (a)(12)(i) through (iii) of this section.
    (i) The owner or operator shall conduct a performance evaluation of 
the CEMS according to the applicable requirements of Sec.  60.13 of 40 
CFR, Performance Specifications 6 or 15 in Appendix B of 40 CFR part 
60, and procedure 2 in Appendix F of 40 CFR part 60.
    (ii) Quarterly accuracy determinations and daily calibration drift 
tests shall be performed in accordance with procedure 1 in Appendix F 
of 40 CFR part 60.
    (13) The owner or operator of an affected source using a CEMS 
measuring SO2 emissions to meet requirements of this subpart 
shall install, certify, operate, and maintain the CEMS as specified in 
paragraphs (a)(13)(i) through (iii) of this section.
    (i) The owner or operator shall conduct a performance evaluation of 
the CEMS according to the applicable requirements of Sec.  60.13 of 40 
CFR part 60, Performance Specification 2 or 6 in Appendix B of 40 CFR 
part 60, and procedure 1 in Appendix F of 40 CFR part 60.
    (ii) Quarterly accuracy determinations and daily calibration drift 
tests shall be performed in accordance with procedure 1 in Appendix F 
of 40 CFR part 60.
    (14) The owner or operator of an affected source using a CEMS 
measuring Hg emissions to meet requirements of this subpart shall 
install, certify, operate, and maintain the CEMS as specified in 
paragraphs (a)(14)(i) through (iii) of this section.
    (i) The owner or operator shall conduct a performance evaluation of 
the CEMS according to the applicable requirements of Appendix A of this 
subpart.
    (ii) Quarterly accuracy determinations and daily calibration drift 
tests shall be performed in accordance with procedure 5 in Appendix F 
of 40 CFR part 60.
    (15) As an alternative to measuring Hg emissions using Hg CEMS, the 
owner or operator of an affected source using a sorbent trap monitoring 
system to meet requirements of this subpart shall install, certify, 
operate, and maintain the sorbent trap monitoring system in accordance 
with Appendix A to this subpart.
    (16) You must conduct a performance tune-up of the EGU to 
demonstrate continuous compliance as specified in paragraphs (a)(16)(i) 
through (a)(16)(vii) of this section.
    (i) As applicable, inspect the burner, and clean or replace any 
components of the burner as necessary (you may delay the burner 
inspection until the next scheduled unit shutdown, but you must inspect 
each burner at least once every 18 months);
    (ii) Inspect the flame pattern, as applicable, and make any 
adjustments to the burner necessary to optimize the flame pattern. The 
adjustment should be consistent with the manufacturer's specifications, 
if available;
    (iii) Inspect the system controlling the air-to-fuel ratio, as 
applicable, and ensure that it is correctly calibrated and functioning 
properly;
    (iv) Optimize total emissions of CO and NOX. This 
optimization should be consistent with the manufacturer's 
specifications, if available;
    (v) Measure the concentration in the effluent stream of CO and 
NOX in ppm, by volume, and oxygen in volume percent, before 
and after the 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); and
    (vi) Maintain on-site and submit, if requested by the 
Administrator, an annual report containing the information in 
paragraphs (a)(16)(vi)(A) through (C) of this section,
    (A) The concentrations of CO and NOX in the effluent 
stream in ppm by volume, and oxygen in volume percent, measured before 
and after the adjustments of the EGU;
    (B) A description of any corrective actions taken as a part of the 
combustion adjustment; and
    (C) The type and amount of fuel used over the 12 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.
    (vii) After December 31, 2011, and within 60 days after the date of 
completing each performance tune-up conducted to demonstrate compliance 
with this subpart, you must submit a notice of completion of the 
performance tune-up to EPA by successfully submitting the data 
electronically into an EPA database.
    (17) For LEEs, the results of your initial and subsequent emissions 
tests, along with records of your fuel analyses, demonstrate your 
continuous compliance and continued eligibility as a LEE.
    (i) As of January 1, 2012 and within 60 days after the date of 
completing each performance test, as defined in Sec.  63.2 and as 
required in this subpart, you must submit performance 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/). Only data collected using test methods 
compatible with ERT are subject to this requirement to be submitted 
electronically into EPA's WebFIRE database.
    (ii) Within 60 days after the date of completing each CEMS 
performance evaluation test, as defined in 63.2 and required by this 
subpart, you must submit the relative accuracy test audit data 
electronically into EPA's Central Data Exchange by using the Electronic

[[Page 25118]]

Reporting Tool as mentioned in paragraph (17)(i) of this section. Only 
data collected using test methods compatible with ERT are subject to 
this requirement to be submitted electronically into EPA's WebFIRE 
database.
    (iii) All reports required by this subpart not subject to the 
requirements in paragraphs (17)(i) and (ii) 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 paragraph (17)(i) and (ii) of this section in paper 
format.
    (b) You must report each instance in which you did not meet each 
emission limit and operating limit in Tables 1 through 4 to this 
subpart that apply to you. These instances are deviations from the 
emission limits in this subpart. These deviations must be reported 
according to the requirements in Sec.  63.10031.
    (c) Consistent with Sec.  63.10010, Sec.  63.10020, and your site-
specific monitoring plan, you must determine the 3-hour rolling average 
of the CPMS data collected for all periods the process is operating.


Sec.  63.10022  How do I demonstrate continuous compliance under the 
emission 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 (8) 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 a wet scrubber for PM control, maintain 
the 3-hour average parameter values at or below the operating limits 
established during the most recent performance test;
    (3) For each existing unit participating in the emissions averaging 
option that is equipped with a fabric filter but without PM CEMS, 
maintain the 3-hour average parameter values at or below the operating 
limits established during the most recent performance test;
    (4) For each existing unit participating in the emissions averaging 
option that is equipped with dry sorbent injection, maintain the 3-hour 
average parameter values at or below the operating limits established 
during the most recent performance test;
    (5) For each existing unit participating in the emissions averaging 
option that is equipped with an ESP, maintain the 3-hour average 
parameter values at or below the operating limits established during 
the most recent performance test;
    (6) For each existing unit participating in the emissions averaging 
option that is equipped with an ESP, maintain the monthly fuel content 
values at or below the operating limits established during the most 
recent performance test;
    (7) For each existing unit participating in the emissions averaging 
option that has an approved alternative operating plan, maintain the 3-
hour average parameter values at or below the operating limits 
established in the most recent performance test.
    (8) 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 (8) 
of this section is a deviation.

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 [DATE 60 DAYS AFTER PUBLICATION OF THE FINAL RULE IN THE 
FEDERAL REGISTER], you must submit an Initial Notification not later 
than 120 days after [DATE 60 DAYS AFTER PUBLICATION OF THE FINAL RULE 
IN THE FEDERAL REGISTER].
    (c) As specified in Sec.  63.9(b)(4) and (b)(5), if you startup 
your new or reconstructed affected source on or after [DATE 60 DAYS 
AFTER PUBLICATION OF THE FINAL RULE IN THE FEDERAL REGISTER], you must 
submit an Initial Notification not later than 15 days after the actual 
date of startup of the affected source.
    (d) If 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) If 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). 
For each initial compliance demonstration, you must submit the 
Notification of Compliance Status, including all performance test 
results and fuel analyses, before the close of business on the 60th day 
following the completion of the performance test and/or other initial 
compliance demonstrations according to Sec.  63.10(d)(2). The 
Notification of Compliance Status report must contain all the 
information specified in paragraphs (e)(1) through (6), 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 and 
fuel analysis; performance testing with operational limits (e.g., CEMS 
for surrogates or CPMS); CEMS; or sorbent trap monitoring system.
    (4) Identification of whether you plan to demonstrate compliance by 
emissions averaging.
    (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 description of the 
deviation, the duration of the deviation, and the corrective action 
taken 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 
certification of compliance and must be signed by a responsible 
official:
    (i) ``This EGU complies with the requirement in Sec.  
63.10021(a)(16)(i) through (vi).''

[[Page 25119]]

Sec.  63.10031  What reports must I submit and when?

    (a) You must submit each report in Table 9 to this subpart that 
applies to you.
    (b) Unless the EPA 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 9 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 delivered 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 
delivered 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 40 CFR part 70 or 40 CFR part 71, 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 (9) of this section.
    (1) Company name and address.
    (2) Statement by a responsible official with that official's name, 
title, and signature, certifying the truth, accuracy, and completeness 
of the content of the report.
    (3) Date of report and beginning and ending dates of the reporting 
period.
    (4) 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.
    (5) 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 
three years consistent with Sec.  63.10006(o) or (p), 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(o) or (p), and a statement as to 
whether there have been any operational changes since the last stack 
test that could increase emissions.
    (6) A signed statement indicating that you burned no new types of 
fuel. Or, if you did burn a new type of fuel, you must submit the 
calculation of chlorine input, using Equation 7 of Sec.  63.10011, that 
demonstrates that your source is still within its maximum chlorine 
input level established during the previous performance testing (for 
sources that demonstrate compliance through performance testing) or you 
must submit the calculation of HCl emission rate using Equation 15 of 
Sec.  63.10011 that demonstrates that your source is still meeting the 
emission limit for HCl emissions (for EGUs that demonstrate compliance 
through fuel analysis). If you burned a new type of fuel, you must 
submit the calculation of Hg input, using Equation 8 of Sec.  63.10011, 
that demonstrates that your source is still within its maximum Hg input 
level established during the previous performance testing (for sources 
that demonstrate compliance through performance testing), or you must 
submit the calculation of Hg emission rate using Equation 11 of Sec.  
63.10011 that demonstrates that your source is still meeting the 
emission limit for Hg emissions (for EGUs that demonstrate compliance 
through fuel analysis).
    (7) If you wish to burn a new type of fuel and you cannot 
demonstrate compliance with the maximum chlorine input operating limit 
using Equation 7 of Sec.  63.10011 or the maximum Hg input operating 
limit using Equation 8 of Sec.  63.10011, you must include in the 
compliance report a statement indicating the intent to conduct a new 
performance test within 60 days of starting to burn the new fuel.
    (8) If there are no deviations from any emission limits or 
operating limits in this subpart that apply to you, a statement that 
there were no deviations from the emission limits or operating limits 
during the reporting period.
    (9) If there were no deviations from the monitoring requirements 
including no periods during which the CMSs, including CEMS, and CPMS, 
were out of control as specified in Sec.  63.8(c)(7), a statement that 
there were no deviations and no periods during which the CMS were out 
of control during the reporting period.
    (10) 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(a)(16)(i) through (vi). 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 deviation from an emission limit or operating limit in 
this subpart that occurs at an affected source where you are not using 
a CMS to comply with that emission limit or operating limit, the 
compliance report must additionally contain the information required in 
paragraphs (d)(1) through (4) of this section.
    (1) The total operating time of each affected source during the 
reporting period.
    (2) A description of the deviation and which emission limit or 
operating limit from which you deviated.
    (3) Information on the number, duration, and cause of deviations 
(including unknown cause), as applicable, and the corrective action 
taken.
    (4) A copy of the test report if the annual performance test showed 
a deviation from the emission limits.
    (e) For each deviation from an emission limit, operating limit, and 
monitoring requirement in this subpart 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 
paragraphs (e)(1) through (12) of this section. This includes any 
deviations from your site-specific monitoring plan as required in Sec.  
63.10000(d).
    (1) The date and time that each deviation started and stopped and 
description of the nature of the deviation (i.e., what you deviated 
from).
    (2) The date and time that each CMS was inoperative, except for 
zero (low-level) and high-level checks.
    (3) The date, time, and duration that each CMS was out of control, 
including the information in Sec.  63.8(c)(8).
    (4) The date and time that each deviation started and stopped, and 
whether each deviation occurred during

[[Page 25120]]

a period of startup, shutdown, or malfunction or during another period.
    (5) A summary of the total duration of the deviation during the 
reporting period and the total duration as a percent of the total 
source operating time during that reporting period.
    (6) An analysis of the total duration of the deviations during the 
reporting period into those that are due to startup, shutdown, control 
equipment problems, process problems, other known causes, and other 
unknown causes.
    (7) A summary of the total duration of CMSs downtime during the 
reporting period and the total duration of CMS downtime as a percent of 
the total source operating time during that reporting period.
    (8) An identification of each parameter that was monitored at the 
affected source for which there was a deviation.
    (9) A brief description of the source for which there was a 
deviation.
    (10) A brief description of each CMS for which there was a 
deviation.
    (11) The date of the latest CMS certification or audit for the 
system for which there was a deviation.
    (12) A description of any changes in CMSs, processes, or controls 
since the last reporting period for the source for which there was a 
deviation.
    (f) Each affected source that has obtained a title V operating 
permit pursuant to 40 CFR part 70 or 40 CFR part 71 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 9 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. However, 
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.
    (g) In addition to the information required in Sec.  63.9(h)(2), 
your notification must include the following certification(s) of 
compliance, as applicable, and signed by a responsible official:
    (1) ``This facility complies with the requirements in Sec.  
63.10021(a)(10) to conduct an annual performance test of the unit''.
    (2) ``No secondary materials that are solid waste were combusted in 
any affected unit.''
    (h)(1) As of January 1, 2012 and within 60 days after the date of 
completing each performance test, as defined in Sec.  63.2 and as 
required in this subpart, you must submit performance 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/). Only data collected using test methods 
compatible with ERT are subject to this requirement to be submitted 
electronically into EPA's WebFIRE database.
    (2) Within 60 days after the date of completing each CEMS 
performance evaluation test, as defined in 63.2 and required by this 
subpart, you must submit the relative accuracy test audit data 
electronically into EPA's Central Data Exchange by using the Electronic 
Reporting Tool as mentioned in paragraph (h)(1) of this section. Only 
data collected using test methods compatible with ERT are subject to 
this requirement to be submitted electronically into EPA's WebFIRE 
database.
    (3) All reports required by this subpart not subject to the 
requirements in paragraphs (h)(1) and (2) 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 paragraph (h)(1) and (2) of this section in paper format.
    (i) If you had a malfunction during the reporting period, the 
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. The report must also include a description of actions 
taken by an owner or operator during a malfunction of an affected 
source to minimize emissions in accordance with Sec.  63.10000(b), 
including actions taken to correct a malfunction.


Sec.  63.10032  What records must I keep?

    (a) You must keep records according to paragraphs (a)(1) through 
(2) of this section.
    (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 8 to this subpart 
including records of all monitoring data and calculated averages for 
applicable operating limits such as pressure drop and pH 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 (5) 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) A copy of all calculations and supporting documentation of 
maximum chlorine fuel input, using Equation 7 of Sec.  63.10011, that 
were done to demonstrate continuous compliance with the HCl emission 
limit, for sources

[[Page 25121]]

that demonstrate compliance through performance testing. For sources 
that demonstrate compliance through fuel analysis, a copy of all 
calculations and supporting documentation of HCl emission rates, using 
Equation 15 of Sec.  63.10011, that were done to demonstrate compliance 
with the HCl emission limit. Supporting documentation should include 
results of any fuel analyses and basis for the estimates of maximum 
chlorine fuel input or HCl emission rates. You can use the results from 
one fuel analysis for multiple EGUs provided they are all burning the 
same fuel type. However, you must calculate chlorine fuel input, or HCl 
emission rate, for each EGU.
    (4) A copy of all calculations and supporting documentation of 
maximum Hg fuel input, using Equation 8 of Sec.  63.10011, that were 
done to demonstrate continuous compliance with the Hg emission limit 
for sources that demonstrate compliance through performance testing. 
For sources that demonstrate compliance through fuel analysis, a copy 
of all calculations and supporting documentation of Hg emission rates, 
using Equation 11 of Sec.  63.10011, that were done to demonstrate 
compliance with the Hg emission limit. Supporting documentation should 
include results of any fuel analyses and basis for the estimates of 
maximum Hg fuel input or Hg emission rates. You can use the results 
from one fuel analysis for multiple EGUs provided they are all burning 
the same fuel type. However, you must calculate Hg fuel input, or Hg 
emission rates, for each EGU.
    (5) If consistent with Sec.  63.10032(b) and (c), you choose to 
stack test less frequently than annually, you must keep annual records 
that document that your emissions in the previous stack test(s) were 
less than 90 percent of the applicable emission limit, 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 emission averaging 
implementation 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) Records of the occurrence and duration of each startup and/or 
shutdown.
    (g) Records of the occurrence and duration of each malfunction of 
operation (i.e., process equipment) or the air pollution control and 
monitoring equipment.
    (h) 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.


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 10 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; however, the U.S. 
EPA retains oversight of this subpart and can take enforcement actions, 
as appropriate.
    (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), and approval of alternative analytical methods 
requested under Sec.  63.10008(b)(2).
    (3) Approval of major change to monitoring under Sec.  63.8(f) and 
as defined in Sec.  63.90, and approval of alternative operating 
parameters under Sec. Sec.  63.9991(a)(2) and 63.10009(g)(2).
    (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-
77, 90, 91, 95, 98a, or 99 (incorporated by reference, see 40 CFR 
63.14(b)(39)).
    Bag leak detection system means a group of instruments that are 
capable of monitoring PM loadings in the exhaust of a fabric filter 
(i.e., baghouse) in order to detect bag failures. A bag leak detection 
system includes, but is not limited to, an instrument that operates on 
electrodynamic, triboelectric, light scattering, light transmittance, 
or other principle to monitor relative PM loadings.
    Bituminous coal means coal that is classified as bituminous 
according to ASTM Method D388-77, 90, 91, 95, 98a, or 99 (Reapproved 
2004) e1 (incorporated by reference, see 40 CFR 
63.14(b)(39)).
    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.
    Coal means all solid fuels classifiable as anthracite, bituminous, 
sub-bituminous, or lignite by ASTM Method D388-991\1\ (incorporated by 
reference,

[[Page 25122]]

see 40 CFR 63.14(b)(39)), 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 or coal refuse either exclusively, in any 
combination together, or in any combination with other fuels in any 
amount.
    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 (or mechanical) and useful thermal 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 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.
    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.
    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 D396-02a (incorporated by reference, see Sec.  
63.14(b)(40)).
    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. 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 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.
    Electrostatic precipitator or ESP means an add-on air pollution 
control device that is located downstream of the steam generating unit 
used to capture PM by charging the particles using an electrostatic 
field, collecting the particles using a grounded collecting surface, 
and transporting the particles into a hopper.
    Emission limitation means any emissions limit or operating limit.
    Equivalent means the following only as this term is used in Table 6 
to subpart UUUUU:
    (1) An equivalent sample collection procedure means a published 
voluntary consensus standard or practice (VCS) or EPA method that 
includes collection of a minimum of three composite fuel samples, with 
each composite consisting of a minimum of three increments collected at 
approximately equal intervals over the test period.
    (2) An equivalent sample compositing procedure means a published 
VCS or EPA method to systematically mix and obtain a representative 
subsample (part) of the composite sample.
    (3) An equivalent sample preparation procedure means a published 
VCS or EPA method that: Clearly states that the standard, practice or 
method is appropriate for the pollutant and the fuel matrix; or is 
cited as an appropriate sample preparation standard, practice or method 
for the pollutant in the chosen VCS or EPA determinative or analytical 
method.
    (4) An equivalent procedure for determining heat content means a 
published VCS or EPA method to obtain gross calorific (or higher 
heating) value.
    (5) An equivalent procedure for determining fuel moisture content 
means a published VCS or EPA method to obtain moisture content. If the 
sample analysis plan calls for determining metals (especially the Hg, 
selenium, or arsenic) using an aliquot of the dried sample, then the 
drying temperature must be modified to prevent vaporizing these metals. 
On the other hand, if metals analysis is done on an ``as received'' 
basis, a separate aliquot can be dried to determine moisture content 
and the metals concentration mathematically adjusted to a dry basis.
    (6) An equivalent pollutant (Hg) determinative or analytical 
procedure means a published VCS or EPA method that clearly states that 
the standard, practice, or method is appropriate for the pollutant and 
the fuel matrix and has a published detection limit equal or lower than 
the methods listed in Table

[[Page 25123]]

6 to subpart UUUUU for the same purpose.
    Fabric filter, or FF, or baghouse means an add-on air pollution 
control device that is located downstream of the steam generating unit 
used to capture PM by filtering gas streams through filter media.
    Federally enforceable means all limitations and conditions that are 
enforceable by the EPA 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.
    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 73 MWe (250 million Btu/
hr, MMBtu/hr) heat input (equivalent to 25 MWe output) of fossil fuels. 
To be ``capable of combusting'' fossil fuels, an EGU would need to have 
these fuels allowed in their permits and have the appropriate fuel 
handling facilities on-site (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 the previous 3 calendar years or for more than 15.0 
percent of the annual heat input during any one of those calendar 
years.
    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, 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 forward 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. Blast furnace gas is exempted from this definition.
    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, 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 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 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 
that burns a synthetic gas derived from coal or solid oil-derived fuel 
in a combined-cycle gas turbine. No 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 D388-77, 90, 91, 95, 98a, or 99 (Reapproved 
2004) [egr]1 (incorporated by reference, see Sec.  
63.14(a)(39)).
    Liquid fuel includes, but is not limited to, distillate oil and 
residual oil.
    Minimum pressure drop means 90 percent of the test average pressure 
drop measured according to Table 7 to this subpart during the most 
recent performance test demonstrating compliance with the applicable 
emission limit.
    Minimum scrubber effluent pH means 90 percent of the test average 
effluent pH measured at the outlet of the wet scrubber according to 
Table 7 to this subpart during the most recent performance test 
demonstrating compliance with the applicable HCl emission limit.
    Minimum scrubber flow rate means 90 percent of the test average 
flow rate measured according to Table 7 to this subpart during the most 
recent performance test demonstrating compliance with the applicable 
emission limit.
    Minimum sorbent injection rate means 90 percent of the test average 
sorbent (or activated carbon) injection rate for each sorbent measured 
according to Table 7 to this subpart during the most recent performance 
test demonstrating compliance with the applicable emission limits.
    Minimum voltage or amperage means 90 percent of the test average 
voltage or amperage to the electrostatic precipitator measured 
according to Table 7 to this subpart during the most recent performance 
test demonstrating compliance with the applicable emission limits.
    Natural gas means:
    (1) A naturally occurring mixture of hydrocarbon and nonhydrocarbon 
gases found in geologic formations beneath the earth's surface, of 
which the principal constituent is methane; or
    (2) Liquid petroleum gas, as defined by ASTM Method D1835-03a 
(incorporated by reference, see Sec.  63.14(b)(41)).
    Net-electric output means the gross electric sales to the utility 
power distribution system minus purchased power on a calendar year 
basis.
    Non-cogeneration unit means a unit that has a combustion unit of 
more than 25 MWe and that supplies more than 25 MWe to any utility 
power distribution system for sale.
    Noncontinental area means the State of Hawaii, the Virgin Islands, 
Guam, American Samoa, the Commonwealth of Puerto Rico, or the Northern 
Mariana Islands.
    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 that either burns oil exclusively, or 
burns oil alternately with burning fuels other than oil at other times.
    Particulate matter or PM means any finely divided solid or liquid 
material, other than uncombined water, as measured by the test methods 
specified under this subpart, or an alternative method.
    Pulverized coal boiler means an EGU in which pulverized coal is 
introduced into an air stream that carries the coal

[[Page 25124]]

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 D396-02a (incorporated by reference, see 
Sec.  63.14(b)(40)).
    Responsible official means responsible official as defined in 40 
CFR 70.2.
    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 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 D388-77, 90, 91, 95, 98a, or 99 
(Reapproved 2004) [epsiv]\1\ (incorporated by reference, see Sec.  
60.14(a)(39)).
    Unit designed for coal  8,300 Btu/lb subcategory 
includes any EGU designed to burn a coal having a calorific value 
(moist, mineral matter-free basis) of greater than or equal to 19,305 
kilojoules per kilogram (kJ/kg) (8,300 British thermal units per pound 
(Btu/lb)) in an EGU with a height-to-depth ratio of less than 3.82.
    Unit designed for coal < 8,300 Btu/lb includes any EGU designed to 
burn a nonagglomerating virgin coal having a calorific value (moist, 
mineral matter-free basis) of less than 19,305 kJ/kg (8,300 Btu/lb) in 
an EGU with a height-to-depth ratio of 3.82 or greater.
    Unit designed to burn liquid oil fuel subcategory includes any EGU 
that burned any liquid 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 gaseous fuels.
    Unit designed to burn solid oil-derived fuel subcategory includes 
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.
    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. 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 their 
rule. When this occurs, EPA has done searches and reviews for VCS 
equivalent to these non-EPA 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

    As stated in Sec.  63.9991, you must comply with the following 
applicable emission limits:

               Table 1 to Subpart UUUUU of Part 63--Emission Limits for New or Reconstructed EGUs
----------------------------------------------------------------------------------------------------------------
                                                                                               Using these
                                                                                            requirements, as
                                                                  You must meet the        appropriate, (e.g.,
      If your EGU is in this           For the following         following emission        specified sampling
        subcategory . . .               pollutants . . .      limits and work practice     volume or test run
                                                                   standards . . .       duration) with the test
                                                                                        methods in Table 5 . . .
----------------------------------------------------------------------------------------------------------------
1. Coal-fired unit designed for    a. Total particulate       0.050 lb per MWh........  Collect a minimum of 4
 coal >= 8,300 Btu/lb.              matter (PM).                                         dscm per run.
                                   OR                         OR                        ........................
                                   Total non-Hg HAP metals..  0.000040 lb per MWh.....  Collect a minimum of 4
                                                                                         dscm per run.
                                   OR                         OR                        ........................
                                   Individual HAP metals:                               Collect a minimum of 4
                                                                                         dscm per run.
                                   Antimony (Sb)............  0.000080 lb/GWh.........  ........................
                                   Arsenic (As).............  0.00020 lb/GWh..........  ........................
                                   Beryllium (Be)...........  0.000030 lb/GWh.........  ........................
                                   Cadmium (Cd).............  0.00040 lb/GWh..........  ........................

[[Page 25125]]

 
                                   Chromium (Cr)............  0.020 lb/GWh............  ........................
                                   Cobalt (Co)..............  0.00080 lb/GWh..........  ........................
                                   Lead (Pb)................  0.00090 lb/GWh..........  ........................
                                   Manganese (Mn)...........  0.0040 lb/GWh...........  ........................
                                   Nickel (Ni)..............  0.0040 lb/GWh...........  ........................
                                   Selenium (Se)............  0.030 lb/GWh............  ........................
                                   b. Hydrogen chloride       0.30 lb per GWh.........  For Method 26A, collect
                                    (HCl).                                               a minimum of 4 dscm per
                                                                                         run.
                                   OR                                                   ........................
                                   Sulfur dioxide (SO2) \1\.  0.40 lb per MWh.........  SO2 CEMS.
                                   c. Mercury (Hg)..........  0.000010 lb per GWh.....  Hg CEMS or Sorbent trap
                                                                                         monitoring system.
----------------------------------------------------------------------------------------------------------------
2. Coal-fired unit designed for    a. Total particulate       0.050 lb per MWh........  Collect a minimum of 4
 coal < 8,300 Btu/lb.               matter (PM).                                         dscm per run.
                                   OR                         OR                        ........................
                                   Total non-Hg HAP metals..  0.000040 lb per MWh.....  Collect a minimum of 4
                                                                                         dscm per run.
                                   OR                         OR                        ........................
                                   Individual HAP metals:                               Collect a minimum of 4
                                                                                         dscm per run.
                                   Antimony (Sb)............  0.000080 lb/GWh.........  ........................
                                   Arsenic (As).............  0.00020 lb/GWh..........  ........................
                                   Beryllium (Be)...........  0.000030 lb/GWh.........  ........................
                                   Cadmium (Cd).............  0.00040 lb/GWh..........  ........................
                                   Chromium (Cr)............  0.020 lb/GWh............  ........................
                                   Cobalt (Co)..............  0.00080 lb/GWh..........  ........................
                                   Lead (Pb)................  0.00090 lb/GWh..........  ........................
                                   Manganese (Mn)...........  0.0040 lb/GWh...........  ........................
                                   Nickel (Ni)..............  0.0040 lb/GWh...........  ........................
                                   Selenium (Se)............  0.030 lb/GWh............  ........................
                                   b. Hydrogen chloride       0.30 lb per GWh.........  For Method 26A, collect
                                    (HCl).                                               a minimum of 4 dscm per
                                                                                         run.
                                   OR                         OR                        ........................
                                   Sulfur dioxide (SO2) \2\.  0.40 lb per MWh.........  SO2 CEMS.
                                   c. Mercury (Hg)..........  0.040 lb per GWh........  Hg CEMS or Sorbent trap
                                                                                         monitoring system.
----------------------------------------------------------------------------------------------------------------
3. IGCC unit.....................  a. Particulate matter      0.050 lb per MWh........  Collect a minimum of 4
                                    (PM).                                                dscm per run.
                                   OR                         OR                        ........................
                                   Total non-Hg HAP metals..  0.000040 lb per MWh.....  Collect a minimum of 4
                                                                                         dscm per run.
                                   OR                         OR                        ........................
                                   Individual HAP metals:                               Collect a minimum of 4
                                                                                         dscm per run.
                                   Antimony (Sb)............  0.000080 lb/GWh.........  ........................
                                   Arsenic (As).............  0.00020 lb/GWh..........  ........................
                                   Beryllium (Be)...........  0.000030 lb/GWh.........  ........................
                                   Cadmium (Cd).............  0.00040 lb/GWh..........  ........................
                                   Chromium (Cr)............  0.020 lb/GWh............  ........................
                                   Cobalt (Co)..............  0.00080 lb/GWh..........  ........................
                                   Lead (Pb)................  0.00090 lb/GWh..........  ........................
                                   Manganese (Mn)...........  0.0040 lb/GWh...........  ........................
                                   Nickel (Ni)..............  0.0040 lb/GWh...........  ........................
                                   Selenium (Se)............  0.030 lb/GWh............  ........................
                                   b. Hydrogen chloride       0.30 lb per GWh.........  For Method 26A, collect
                                    (HCl).                                               a minimum of 4 dscm per
                                                                                         run.
                                   OR                                                   ........................
                                   Sulfur dioxide (SO2) \3\.  0.40 lb per MWh.........  SO2 CEMS.
                                   c. Mercury (Hg)..........  0.000010 lb per GWh.....  Hg CEMS or Sorbent trap
                                                                                         monitoring system.
----------------------------------------------------------------------------------------------------------------
4. Liquid oil-fired unit.........  a. Total HAP metals......  0.00040 lb/MWh..........  Collect a minimum of 4
                                                                                         dscm per run.
                                   OR                         OR                        ........................
                                   Individual HAP metals:                               Collect a minimum of 4
                                                                                         dscm per run.
                                   Antimony (Sb)............  0.0020 lb/GWh...........  ........................

[[Page 25126]]

 
                                   Arsenic (As).............  0.0020 lb/GWh...........  ........................
                                   Beryllium (Be)...........  0.00070 lb/GWh..........  ........................
                                   Cadmium (Cd).............  0.00040 lb/GWh..........  ........................
                                   Chromium (Cr)............  0.020 lb/GWh............  ........................
                                   Cobalt (Co)..............  0.0060 lb/GWh...........  ........................
                                   Lead (Pb)................  0.0060 lb/GWh...........  ........................
                                   Manganese (Mn)...........  0.030 lb/GWh............  ........................
                                   Nickel (Ni)..............  0.040 lb/GWh............  ........................
                                   Selenium (Se)............  0.0040 lb/GWh...........  ........................
                                   Mercury (Hg).............  0.00010 lb/GWh..........  For Method 30B sample
                                                                                         volume determination
                                                                                         (8.2.4), the estimated
                                                                                         Hg concentration should
                                                                                         nominally be < \1/2\
                                                                                         the standard.
                                   b. Hydrogen chloride       0.00050 lb/MWh..........  For Method 26A, collect
                                    (HCl).                                               a minimum of 4 dscm per
                                                                                         run.
                                   c. Hydrogen fluoride (HF)  0.00050 lb/MWh..........  For Method 26A, collect
                                                                                         a minimum of 4 dscm per
                                                                                         run.
----------------------------------------------------------------------------------------------------------------
5. Solid oil-derived fuel-fired    a. Particulate matter      0.050 lb/MWh............  Collect a minimum of 4
 unit.                              (PM).                                                dscm per run.
                                   OR                         OR                        ........................
                                   Total non-Hg HAP metals..  0.00020 lb/MWh..........  Collect a minimum of 4
                                                                                         dscm per run.
                                   OR                         OR                        ........................
                                   Individual HAP metals:                               Collect a minimum of 4
                                                                                         dscm per run.
                                   Antimony (Sb)............  0.00090 lb/GWh..........  ........................
                                   Arsenic (As).............  0.0020 lb/GWh...........  ........................
                                   Beryllium (Be)...........  0.000080 lb/GWh.........  ........................
                                   Cadmium (Cd).............  0.0070 lb/GWh...........  ........................
                                   Chromium (Cr)............  0.0060 lb/GWh...........  ........................
                                   Cobalt (Co)..............  0.0020 lb/GWh...........  ........................
                                   Lead (Pb)................  0.020 lb/GWh............  ........................
                                   Manganese (Mn)...........  0.0070 lb/GWh...........  ........................
                                   Nickel (Ni)..............  0.0070 lb/GWh...........  ........................
                                   Selenium (Se)............  0.00090 lb/GWh..........  ........................
                                   b. Hydrogen chloride       0.00030 lb/MWh..........  For Method 26A, collect
                                    (HCl).                                               a minimum of 4 dscm per
                                                                                         run.
                                   OR                                                   ........................
                                   Sulfur dioxide (SO2) \4\.  0.40 lb/MWh.............  SO2 CEMS.
                                   c. Mercury (Hg)..........  0.0020 lb/GWh...........  Hg CEMS or Sorbent trap
                                                                                         monitoring system.
----------------------------------------------------------------------------------------------------------------

    As stated in Sec.  63.9991, you must comply with the following 
applicable emission limits: \5\

                     Table 2 to Subpart UUUUU of Part 63--Emission Limits for Existing EGUs
----------------------------------------------------------------------------------------------------------------
                                                                                               Using these
                                                                                             requirements, as
                                                                   You must meet the        appropriate (e.g.,
 If your EGU is in this subcategory .     For the following        following emission       specified sampling
                 . .                       pollutants . . .         limits and work         volume or test run
                                                                 practice standards . .  duration) with the test
                                                                           .              methods in Table 5 . .
                                                                                                    .
----------------------------------------------------------------------------------------------------------------
1. Coal-fired unit designed for coal   a. Total particulate     0.030 lb/MMBtu or 0.30   Collect a minimum of 2
 >= 8,300 Btu/lb.                       matter (PM).             lb/MWh.                  dscm per run.
                                       OR                       OR
                                       Total non-Hg HAP metals  0.000040 lb/MMBtu        Collect a minimum of 4
                                                                0.00040 lb/MWh.........   dscm per run.
                                       OR                       OR
                                       Individual HAP metals:                            Collect a minimum of 4
                                                                                          dscm per run.
                                       Antimony (Sb)..........  0.60 lb/TBtu or 0.0060
                                                                 lb/GWh.
                                       Arsenic (As)...........  2.0 lb/TBtu or 0.020 lb/
                                                                 GWh.
                                       Beryllium (Be).........  0.20 lb/TBtu or 0.0020
                                                                 lb/GWh.
                                       Cadmium (Cd)...........  0.30 lb/TBtu or 0.0030
                                                                 lb/GWh.

[[Page 25127]]

 
                                       Chromium (Cr)..........  3.0 lb/TBtu or 0.030 lb/
                                                                 GWh.
                                       Cobalt (Co)............  0.80 lb/TBtu or 0.0080
                                                                 lb/GWh.
                                       Lead (Pb)..............  2.0 lb/TBtu or 0.020 lb/
                                                                 GWh.
                                       Manganese (Mn).........  5.0 lb/TBtu or 0.050 lb/
                                                                 GWh.
                                       Nickel (Ni)............  4.0 lb/TBtu or 0.040 lb/
                                                                 GWh.
                                       Selenium (Se)..........  6.0 lb/TBtu or 0.060 lb/
                                                                 GWh.
                                       b. Hydrogen chloride     0.0020 lb per MMBtu or   For Method 26A, collect
                                        (HCl).                   0.020 lb per MWh.        a minimum of 0.75 dscm
                                                                                          per run; for Method
                                                                                          26, collect a minimum
                                                                                          of 60 liters per run.
                                       OR
                                       Sulfur dioxide (SO2)     0.20 lb per MMBtu or     SO2 CEMS.
                                        \6\.                     2.0 lb per MWh.
                                       c. Mercury (Hg)........  1.0 lb/TBtu or 0.008 lb/ LEE Testing for 28-30
                                                                 GWh.                     days with 10 days
                                                                                          maximum per run or Hg
                                                                                          CEMS or Sorbent trap
                                                                                          monitoring system.
----------------------------------------------------------------------------------------------------------------
2. Coal-fired unit designed for coal.  a. Total particulate     0.030 lb/MMBtu or 0.30   Collect a minimum of 4
< 8,300 Btu/lb.......................   matter (PM).             lb/MWh.                  dscm per run.
                                       OR                       OR
                                       Total non-Hg HAP metals  0.000040 lb/MMBtu        Collect a minimum of 4
                                                                0.00040 lb/MWh.........   dscm per run.
                                       OR                       OR
                                       Individual HAP metals:                            Collect a minimum of 4
                                                                                          dscm per run.
                                       Antimony (Sb)..........  0.60 lb/TBtu or 0.0060
                                                                 lb/GWh.
                                       Arsenic (As)...........  2.0 lb/TBtu or 0.020 lb/
                                                                 GWh.
                                       Beryllium (Be).........  0.20 lb/TBtu or 0.0020
                                                                 lb/GWh.
                                       Cadmium (Cd)...........  0.30 lb/TBtu or 0.0030
                                                                 lb/GWh.
                                       Chromium (Cr)..........  3.0 lb/TBtu or 0.030 lb/
                                                                 GWh.
                                       Cobalt (Co)............  0.80 lb/TBtu or 0.0080
                                                                 lb/GWh.
                                       Lead (Pb)..............  2.0 lb/TBtu or 0.020 lb/
                                                                 GWh.
                                       Manganese (Mn).........  5.0 lb/TBtu or 0.050 lb/
                                                                 GWh.
                                       Nickel (Ni)............  4.0 lb/TBtu or 0.040 lb/
                                                                 GWh.
                                       Selenium (Se)..........  6.0 lb/TBtu or 0.060 lb/
                                                                 GWh.
                                       b. Hydrogen chloride     0.0020 lb per MMBtu or   For Method 26A, collect
                                        (HCl).                   0.020 lb per MWh.        a minimum of 0.75 dscm
                                                                                          per run; for Method
                                                                                          26, collect a minimum
                                                                                          of 60 liters per run.
                                       OR
                                       Sulfur dioxide (SO2)     0.20 lb per MMBtu or     SO2 CEMS.
                                        \7\.                     2.0 lb per MWh.
                                       c. Mercury (Hg)........  4.0 lb/TBtu or 0.040 lb/ LEE Testing for 28-30
                                                                 GWh.                     days with 10 days
                                                                                          maximum per run or Hg
                                                                                          CEMS or Sorbent trap
                                                                                          monitoring system.
----------------------------------------------------------------------------------------------------------------
3. IGCC unit.........................  a. Total particulate     0.050 lb/MMBtu or 0.30   Collect a minimum of 4
                                        matter (PM).             lb/MWh.                  dscm per run.
                                       OR                       OR
                                       Total non-Hg HAP metals  5.0 lb/TBtu or 0.050 lb/ Collect a minimum of 4
                                                                 GWh.                     dscm per run.
                                       OR                       OR
                                       Individual HAP metals:                            Collect a minimum of 4
                                                                                          dscm per run.
                                       Antimony (Sb)..........  0.40 lb/TBtu or 0.0040
                                                                 lb/GWh.
                                       Arsenic (As)...........  2.0 lb/TBtu or 0.020 lb/
                                                                 GWh.
                                       Beryllium (Be).........  0.030 lb/TBtu or 0.0030
                                                                 lb/GWh.
                                       Cadmium (Cd)...........  0.20 lb/TBtu or 0.0020
                                                                 lb/GWh.
                                       Chromium (Cr)..........  3.0 lb/TBtu or 0.020 lb/
                                                                 GWh.
                                       Cobalt (Co)............  2.0 lb/TBtu or 0.0040
                                                                 lb/GWh.
                                       Lead (Pb)..............  0.0002 lb/MMBtu or
                                                                 0.003 lb/MWh.
                                       Manganese (Mn).........  3.0 lb/TBtu or 0.020 lb/
                                                                 GWh.
                                       Nickel (Ni)............  5.0 lb/TBtu or 0.050 lb/
                                                                 GWh.
                                       Selenium (Se)..........  22.0 lb/TBtu or 0.20 lb/
                                                                 GWh.
                                       b. Hydrogen chloride     0.00050 lb/MMBtu or      For Method 26A, collect
                                        (HCl).                   0.0030 lb/MWh.           a minimum of 4 dscm
                                                                                          per run.

[[Page 25128]]

 
                                       c. Mercury (Hg)........  3.0 lb/TBtu or 0.020 lb/ LEE Testing for 28-30
                                                                 GWh.                     days with 10 days
                                                                                          maximum per run or Hg
                                                                                          CEMS or Sorbent trap
                                                                                          monitoring system.
----------------------------------------------------------------------------------------------------------------
4. Liquid oil-fired unit.............  a. Total HAP metals....  0.000030 lb/MMBtu or     Collect a minimum of 4
                                                                 0.00030 lb/MWh.          dscm per run.
                                       OR                       OR
                                       Individual HAP metals:                            Collect a minimum of 4
                                                                                          dscm per run.
                                       Antimony (Sb)..........  0.20 lb/TBtu or 0.0030
                                                                 lb/GWh.
                                       Arsenic (As)...........  0.60 lb/TBtu or 0.0070
                                                                 lb/GWh.
                                       Beryllium (Be).........  0.060 lb/TBtu or
                                                                 0.00070 lb/GWh.
                                       Cadmium (Cd)...........  0.10 lb/TBtu or 0.0020
                                                                 lb/GWh.
                                       Chromium (Cr)..........  2.0 lb/TBtu or 0.020 lb/
                                                                 GWh.
                                       Cobalt (Co)............  3.0 lb/TBtu or 0.020 lb/
                                                                 GWh.
                                       Lead (Pb)..............  2.0 lb/TBtu or 0.030 lb/
                                                                 GWh.
                                       Manganese (Mn).........  5.0 lb/TBtu or 0.060 lb/
                                                                 GWh.
                                       Nickel (Ni)............  8.0 lb/TBtu or 0.080 lb/
                                                                 GWh.
                                       Selenium (Se)..........  2.0 lb/TBtu or 0.020 lb/
                                                                 GWh.
                                       Mercury (Hg)...........  0.050 lb/TBtu or         For Method 29, collect
                                                                 0.00070 lb/GWh.          a minimum of 4 dscm
                                                                                          per run or for Method
                                                                                          30B sample volume
                                                                                          determination (8.2.4),
                                                                                          the estimated Hg
                                                                                          concentration should
                                                                                          nominally be < \1/2\
                                                                                          the standard.
                                       b. Hydrogen chloride     0.00030 lb/MMBtu or      For Method 26A, collect
                                        (HCl).                   0.0030 lb/MWh.           a minimum of 4 dscm
                                                                                          per run.
                                       c. Hydrogen fluoride     0.00020 lb/MMBtu or      For Method 26A, collect
                                        (HF).                    0.0020 lb/MWh.           a minimum of 4 dscm
                                                                                          per run.
----------------------------------------------------------------------------------------------------------------
5. Solid oil-derived fuel-fired unit.  a. Total particulate     0.20 lb/MMBtu or 2.0 lb/ Collect a minimum of 2
                                        matter (PM).             MWh.                     dscm per run.
                                       OR                       OR
                                       Total non-Hg HAP metals  0.000050 lb/MMBtu or     Collect a minimum of 2
                                                                 0.0010 lb/MWh.           dscm per run.
                                       OR                       OR
                                       Individual HAP metals:                            Collect a minimum of 4
                                                                                          dscm per run.
                                       Antimony (Sb)..........  0.40 lb/TBtu or 0.0070
                                                                 lb/GWh.
                                       Arsenic (As)...........  0.40 lb/TBtu or 0.0040
                                                                 lb/GWh.
                                       Beryllium (Be).........  0.070 lb/TBtu or
                                                                 0.00070 lb/GWh.
                                       Cadmium (Cd)...........  0.40 lb/TBtu or 0.0040
                                                                 lb/GWh.
                                       Chromium (Cr)..........  2.0 lb/TBtu or 0.020 lb/
                                                                 GWh.
                                       Cobalt (Co)............  2.0 lb/TBtu or 0.020 lb/
                                                                 GWh.
                                       Lead (Pb)..............  11.0 lb/TBtu or 0.020
                                                                 lb/GWh.
                                       Manganese (Mn).........  3.0 lb/TBtu or 0.040 lb/
                                                                 GWh.
                                       Nickel (Ni)............  9.0 lb/TBtu or 0.090 lb/
                                                                 GWh.
                                       Selenium (Se)..........  2.0 lb/TBtu 0.020 lb/
                                                                 GWh.
                                       b. Hydrogen chloride     0.0050 lb/MMBtu or       For Method 26A, collect
                                        (HCl).                   0.080 lb/GWh.            a minimum of 1 dscm
                                                                                          per run; for Method
                                                                                          26, collect a minimum
                                                                                          of 60 liters per run.
                                       OR
                                       Sulfur dioxide (SO2)     0.40 lb/MMBtu or 5.0 lb/ SO2 CEMS.
                                        \8\.                     MWh.
                                       c. Mercury (Hg)........  0.20 lb/TBtu or 0.0020   LEE Testing for 28-30
                                                                 lb/GWh.                  days with 10 days
                                                                                          maximum per run or Hg
                                                                                          CEMS or Sorbent trap
                                                                                          monitoring system.
----------------------------------------------------------------------------------------------------------------
\5\ footnote.
\6\ footnote.
\7\ footnote.
\8\ The alternate sulfur dioxide limit may not be used if your EGU does not have some form of flue gas
  desulfurization system installed.

    As stated in Sec.  63.9991, you must comply with the following 
applicable work practice standards:

[[Page 25129]]



      Table 3 to Subpart UUUUU of Part 63--Work Practice Standards
------------------------------------------------------------------------
                                                   You must meet the
             If your EGU is . . .                   following . . .
------------------------------------------------------------------------
1. An existing EGU...........................  Conduct a performance
                                                test of the EGU annually
                                                as specified in Sec.
                                                63.10005.
2. A new EGU.................................  Conduct a performance
                                                test of the EGU annually
                                                as specified in Sec.
                                                63.10005.
------------------------------------------------------------------------


     Table 4 to Subpart UUUUU of Part 63--Operating Limits for EGUs
------------------------------------------------------------------------
                                                  You must meet these
  If you demonstrate compliance using . . .      operating limits . . .
------------------------------------------------------------------------
1. Wet PM scrubber control...................  a. Maintain the pressure
                                                drop at or above the
                                                lowest 1-hour average
                                                pressure drop across the
                                                wet scrubber and the
                                                liquid flow rate at or
                                                above the lowest 1-hour
                                                average liquid flow rate
                                                measured during the most
                                                recent performance test
                                                demonstrating compliance
                                                with the PM emissions
                                                limitation.
2. Wet acid gas scrubbers....................  a. Maintain the pH at or
                                                above the lowest 1-hour
                                                average pressure drop
                                                across the wet scrubber
                                                and the liquid flow-rate
                                                at or above the lowest 1-
                                                hour average liquid flow
                                                rate measured during the
                                                most recent performance
                                                test demonstrating
                                                compliance with the HCl
                                                emissions limitation.
3. Fabric filter control.....................  a. Install and operate a
                                                bag leak detection
                                                system according to Sec.
                                                  63.10010 and operate
                                                the fabric filter such
                                                that the bag leak
                                                detection system does
                                                not initiate alarm mode
                                                more than 5 percent of
                                                the operating time
                                                during each 6-month
                                                period.
4. Electrostatic precipitator control........  a. This option is only
                                                for EGUs that operate
                                                additional wet control
                                                systems. Maintain the
                                                secondary power input of
                                                the electrostatic
                                                precipitator at or above
                                                the lowest 1-hour
                                                average secondary power
                                                measured during the most
                                                recent performance test
                                                demonstrating compliance
                                                with the PM emissions
                                                limitation.
5. Dry scrubber, DSI, or carbon injection      Maintain the sorbent or
 control.                                       carbon injection rate at
                                                or above the lowest 1-
                                                hour average sorbent
                                                flow rate measured
                                                during the most recent
                                                performance test
                                                demonstrating compliance
                                                with the Hg emissions
                                                limitation.
6. Fuel analysis.............................  Maintain the fuel type or
                                                fuel mixture such that
                                                the applicable emission
                                                rate calculated
                                                according to Sec.
                                                63.10011(d)(3), (4) and/
                                                or (5) is less than the
                                                applicable emission
                                                limits.
7. Performance testing.......................  For EGUs that demonstrate
                                                compliance with a
                                                performance test,
                                                maintain the operating
                                                load of each unit such
                                                that it does not exceed
                                                110 percent of the
                                                average operating load
                                                recorded during the most
                                                recent performance test.
8. PM CEMS...................................  Maintain the PM
                                                concentration (mg/dscm)
                                                at or below the highest
                                                1-hour average measured
                                                during the most recent
                                                performance test
                                                demonstrating compliance
                                                with the total PM
                                                emissions limitation.
------------------------------------------------------------------------

    As stated in Sec.  63.10007, you must comply with the following 
requirements for performance testing for existing, new or reconstructed 
affected sources: \9\
---------------------------------------------------------------------------

    \9\ For emissions calculations involving periods of startup or 
shutdown, use procedures in Sec.  63.10005(l).

                   Table 5 to Subpart UUUUU of Part 63--Performance Stack Testing Requirements
----------------------------------------------------------------------------------------------------------------
  To conduct a performance test for
    the following pollutant . . .           Using . . .             You must . . .           Using . . .\10\
----------------------------------------------------------------------------------------------------------------
1. Particulate matter (PM)..........  Emissions Testing......  a. Select sampling ports  Method 1 at 40 CFR part
                                                                location and the number   60, Appendix A-1 of
                                                                of traverse points.       this chapter.
                                                               b. Determine velocity     Method 2, 2F, or 2G at
                                                                and volumetric flow-      40 CFR part 60,
                                                                rate of the stack gas.    Appendix A-1 or A-2 to
                                                                                          part 60 of this
                                                                                          chapter.
                                                               c. Determine oxygen and   Method 3A or 3B at 40
                                                                carbon dioxide            CFR part 60, Appendix
                                                                concentrations of the     A-2 to part 60 of this
                                                                stack gas.                chapter, or ANSI/ASME
                                                                                          PTC 19.10-1981.
                                                               d. Measure the moisture   Method 4 at 40 CFR part
                                                                content of the stack      60, Appendix A-3 of
                                                                gas.                      this chapter.
                                                               e. Measure the PM         Method 202 at 40 CFR
                                                                emissions                 part 51, Appendix M of
                                                                concentrations and        this chapter for
                                                                determine the             condensable PM
                                                                filterable and            emissions from units
                                                                condensable fractions,    and Method 5 (positive
                                                                as well as total PM.      pressure fabric
                                                                                          filters must use
                                                                                          Method 5D) at 40 CFR
                                                                                          part 60, Appendix A-3
                                                                                          or A-6 of this chapter
                                                                                          for filterable PM
                                                                                          emissions. Note that
                                                                                          the Method 5 front
                                                                                          half temperature shall
                                                                                          be 320 [deg]F  25 [deg]F.
                                                               f. Convert emissions      Method 19 F-factor
                                                                concentration to lb per   methodology at 40 CFR
                                                                MMBtu emissions rates     part 60, Appendix A-7
                                                                or lb/MWh emissions       of this chapter, or
                                                                rates.                    calculate using mass
                                                                                          emissions rate and
                                                                                          electrical output
                                                                                          data.
----------------------------------------------------------------------------------------------------------------
2. Total or individual non-Hg HAP     Emissions Testing......  a. Select sampling ports  Method 1 at 40 CFR part
 metals.                                                        location and the number   60, Appendix A-1 of
                                                                of traverse points.       this chapter.

[[Page 25130]]

 
                                                               b. Determine velocity     Method 2, 2F, or 2G at
                                                                and volumetric flow-      40 CFR part 60,
                                                                rate of the stack gas.    Appendix A-1 or A-2 to
                                                                                          part 60 of this
                                                                                          chapter.
                                                               c. Determine oxygen and   Method 3A or 3B at 40
                                                                carbon dioxide            CFR part 60, Appendix
                                                                concentrations of the     A-2 to part 60 of this
                                                                stack gas.                chapter, or ANSI/ASME
                                                                                          PTC 19.10-1981.
                                                               d. Measure the moisture   Method 4 at 40 CFR part
                                                                content of the stack      60, Appendix A-3 of
                                                                gas.                      this chapter.
                                                               e. Measure the HAP        Method 29 at 40 CFR
                                                                metals emissions          part 60, Appendix A-8
                                                                concentrations and        of this chapter.
                                                                determine each            Determine total
                                                                individual HAP metals     filterable HAP metals
                                                                emissions                 according to section
                                                                concentration, as well    8.3.1.1 prior to
                                                                as the total filterable   beginning metals
                                                                HAP metals emissions      analyses.
                                                                concentration and total
                                                                HAP metals emissions
                                                                concentration.
                                                               f. Convert emissions      Method 19 F-factor
                                                                concentrations            methodology at 40 CFR
                                                                (individual HAP metals,   part 60, Appendix A-7
                                                                total filterable HAP      of this chapter, or
                                                                metals, and total HAP     calculate using mass
                                                                metals) to lb per MMBtu   emissions rate and
                                                                or lb per MWh emissions   electrical output
                                                                rates.                    data.
----------------------------------------------------------------------------------------------------------------
3. Hydrogen chloride (HCl) and        Emissions Testing......  a. Select sampling ports  Method 1 at 40 CFR part
 hydrogen fluoride (HF).                                        location and the number   60, Appendix A-1 of
                                                                of traverse points.       this chapter.
                                                               b. Determine velocity     Method 2, 2F, or 2G at
                                                                and volumetric flow-      40 CFR part 60,
                                                                rate of the stack gas.    Appendix A-2 of this
                                                                                          chapter.
                                                               c. Determine oxygen and   Method 3A or 3B at 40
                                                                carbon dioxide            CFR part 60, Appendix
                                                                concentrations of the     A-2 of this chapter,
                                                                stack gas.                or ANSI/ASME PTC 19.10-
                                                                                          1981.
                                                               d. Measure the moisture   Method 4 at 40 CFR part
                                                                content of the stack      60, Appendix A-3 of
                                                                gas.                      this chapter.
                                                               e. Measure the HCl and    Method 26 if there are
                                                                HF emissions              no entrained water
                                                                concentrations.           droplets in the
                                                                                          exhaust stream or 26A
                                                                                          if there are entrained
                                                                                          water droplets in the
                                                                                          exhaust stream at 40
                                                                                          CFR part 60, Appendix
                                                                                          A-8 of this chapter.
                                                               f. Convert emissions      Method 19 F-factor
                                                                concentration to lb per   methodology at 40 CFR
                                                                MMBtu or lb per MWh       part 60, Appendix A-7
                                                                emissions rates.          of this chapter, or
                                                                                          calculate using mass
                                                                                          emissions rate and
                                                                                          electrical output
                                                                                          data.
                                      OR                       OR                        .......................
                                      HCl and/or HF CEMS.....  a. Install, operate, and  PS 15 or 6 at 40 CFR
                                                                maintain the CEMS.        part 60, Appendix B of
                                                                                          this chapter and QA
                                                                                          Procedure 1 at 40 CFR
                                                                                          part 60, Appendix F of
                                                                                          this chapter.
                                                               b. Install, operate, and  Section 4.1.3 and 5.3
                                                                maintain the diluents     of Appendix A of this
                                                                gas, flow rate, and/or    subpart.
                                                                moisture monitoring
                                                                systems.
                                                               c. Convert hourly         Method 19 F-factor
                                                                emissions                 methodology at 40 CFR
                                                                concentrations to 30      part 60, Appendix A-7
                                                                boiler operating day      of this chapter, or
                                                                rolling average lb per    calculate using mass
                                                                MMBtu emissions rates     emissions rate and
                                                                or lb/MWh emissions       electrical output
                                                                rates.                    data.
----------------------------------------------------------------------------------------------------------------
4. Mercury (Hg).....................  Emissions Testing......  a. Select sampling ports  Method 1 at 40 CFR part
                                                                location and the number   60, Appendix A-1 of
                                                                of traverse points.       this chapter.
                                                               b. Determine velocity     Method 2, 2F, or 2G at
                                                                and volumetric flow-      40 CFR part 60,
                                                                rate of the stack gas.    Appendix A-1 or A-2 of
                                                                                          this chapter.
                                                               c. Determine oxygen and   Method 3A or 3B at 40
                                                                carbon dioxide            CFR part 60, Appendix
                                                                concentrations of the     A-1 of this chapter,
                                                                stack gas.                or ANSI/ASME PTC 19.10-
                                                                                          1981.
                                                               d. Measure the moisture   Method 4 at 40 CFR part
                                                                content of the stack      60, Appendix A-3 of
                                                                gas.                      this chapter.
                                                               e. Measure the Hg         Method 29 or 30B at 40
                                                                emission concentration.   CFR part 60, Appendix
                                                                                          A-8 of this chapter or
                                                                                          ASTM Method D6784-02
                                                                                          (2008) as specified.
                                                               f. Convert emissions      Section 6 of Appendix A
                                                                concentration to lb per   of this subpart.
                                                                TBtu emissions rates.
                                      OR                       OR                        .......................
                                      Hg CEMS................  a. Install, operate, and  Sections 3.2.1 and 5.1
                                                                maintain the CEMS.        of Appendix A of this
                                                                                          subpart.
                                                               b. Install, operate, and  Section 4.1.3 and 5.3
                                                                maintain the diluents     of Appendix A of this
                                                                gas, flow rate, and/or    subpart.
                                                                moisture monitoring
                                                                systems.

[[Page 25131]]

 
                                                               c. Convert hourly         Section 6 of Appendix A
                                                                emissions                 of this subpart.
                                                                concentrations to 30
                                                                boiler operating day
                                                                rolling average lb per
                                                                MMBtu emissions rates
                                                                or lb/MWh emissions
                                                                rates.
                                      OR                       OR                        .......................
                                      Sorbent trap monitoring  a. Install, operate, and  Sections 3.2.2 and 5.2
                                       system                   maintain the sorbent      of Appendix A of this
                                                                trap monitoring system.   subpart.
                                                               b. Install, operate, and  Section 4.1.3 and 5.3
                                                                maintain the diluents     of Appendix A of this
                                                                gas, flow rate, and/or    subpart.
                                                                moisture monitoring
                                                                systems.
                                                               c. Convert emissions      Section 6 of Appendix A
                                                                concentrations to 30      of this subpart.
                                                                boiler operating day
                                                                rolling average lb per
                                                                MMBtu emissions rates
                                                                or lb/MWh emissions
                                                                rates.
                                      OR                       OR                        .......................
                                      LEE testing              a. Select sampling ports  Single point located at
                                                                location and the number   the 10% centroidal
                                                                of traverse points.       area of the duct at a
                                                                                          port location per
                                                                                          Method 1 at 40 CFR
                                                                                          part 60, Appendix A-1
                                                                                          of this chapter.
                                                               b. Determine velocity     Method 2, 2F, or 2G at
                                                                and volumetric flow-      40 CFR part 60,
                                                                rate of the stack gas.    Appendix A-1 or A-2 of
                                                                                          this chapter or flow
                                                                                          monitoring systems
                                                                                          certified by Section
                                                                                          4.1.3 and 5.3 of
                                                                                          Appendix A of this
                                                                                          subpart.
                                                               c. Determine oxygen and   Method 3A or 3B at 40
                                                                carbon dioxide            CFR part 60, Appendix
                                                                concentrations of the     A-1 of this chapter,
                                                                stack gas.                or ANSI/ASME PTC 19.10-
                                                                                          1981 or diluent gas
                                                                                          monitoring systems
                                                                                          certified by Section
                                                                                          4.1.3 and 5.3 of
                                                                                          Appendix A of this
                                                                                          subpart.
                                                               d. Measure the moisture   Method 4 at 40 CFR part
                                                                content of the stack      60, Appendix A-3 of
                                                                gas.                      this chapter or
                                                                                          moisture monitoring
                                                                                          systems certified by
                                                                                          Section 4.1.3 and 5.3
                                                                                          of Appendix A of this
                                                                                          subpart.
                                                               e. Measure the Hg         Method 30B at 40 CFR
                                                                emission concentration.   part 60, Appendix A-8
                                                                                          of this chapter.
                                                               f. Convert emissions      Section 6 of Appendix A
                                                                concentrations to 30      of this subpart.
                                                                boiler operating day
                                                                rolling average lb per
                                                                MMBtu emissions rates
                                                                or lb/MWh emissions
                                                                rates.
                                                               g. Convert 30 boiler      Potential maximum
                                                                operating day rolling     annual heat input in
                                                                average lb per MMBtu pr   MMBtu or potential
                                                                lb/MWh to lb per year.    maximum electricity
                                                                                          generated in MWh.
----------------------------------------------------------------------------------------------------------------
5. Sulfur dioxide (SO2).............  SO2 CEMS...............  a. Install, operate, and  PS 2 or 6 at 40 CFR
                                                                maintain the CEMS.        part 60, Appendix B of
                                                                                          this chapter and QA
                                                                                          Procedure 1 at 40 CFR
                                                                                          part 60, Appendix F of
                                                                                          this chapter.
                                                               b. Install, operate, and  Section 4.1.3 and 5.3
                                                                maintain the diluents     of Appendix A of this
                                                                gas, flow rate, and/or    subpart.
                                                                moisture monitoring
                                                                systems.
                                                               c. Convert hourly         Method 19 F-factor
                                                                emissions                 methodology at 40 CFR
                                                                concentrations to 30      part 60, Appendix A-7
                                                                boiler operating day      of this chapter, or
                                                                rolling average lb per    calculate using mass
                                                                MMBtu emissions rates     emissions rate and
                                                                or lb/MWh emissions       electrical output
                                                                rates.                    data.
----------------------------------------------------------------------------------------------------------------

    As stated in Sec.  63.10008, you must comply with the following 
requirements for fuel analysis testing for existing, new, or 
reconstructed affected sources. However, equivalent methods may be used 
in lieu of the prescribed methods at the discretion of the source owner 
or operator:
---------------------------------------------------------------------------

    \10\ All ASTM, ANSI, and ASME methods are incorporated by 
reference.
    \11\ All ASTM, ANSI, and ASME methods are incorporated by 
reference.

     Table 6 to Subpart UUUUU of Part 63--Fuel Analysis Requirements
------------------------------------------------------------------------
To conduct a fuel analysis for
 the following pollutant . . .    You must . . .      Using . . . \11\
 
------------------------------------------------------------------------
1. Mercury (Hg)...............  a. Collect fuel    Procedure in Sec.
                                 samples.           63.10008(c) or ASTM
                                                    D2234/D2234M (for
                                                    coal) or equivalent.
                                b. Composite fuel  Procedure in Sec.
                                 samples.           63.10008(d) or
                                                    equivalent.

[[Page 25132]]

 
                                c. Prepare         EPA SW-846-3020A (for
                                 composited fuel    liquid samples) or
                                 samples.           ASTM D2013/D2013M-
                                                    (for coal) or
                                                    equivalent.
                                d. Determine heat  ASTM D5865 (for coal)
                                 content of the     or equivalent.
                                 fuel type.
                                e. Determine       ASTM D3173 or
                                 moisture content   equivalent.
                                 of the fuel type.
                                f. Measure Hg      ASTM D6722-01 (for
                                 concentration in   coal) or SW-846-
                                 fuel sample.       7471A (for solid
                                                    samples) or SW-846-
                                                    7470A (for liquid
                                                    samples) or
                                                    equivalent.
                                g. Convert         Method 19 F-factor
                                 concentration      methodology at 40
                                 into units of      CFR part 60,
                                 pounds of          Appendix A-7 of this
                                 pollutant per      chapter, or
                                 TBtu of heat       calculate using mass
                                 content or lb      emissions rate and
                                 per MWh.           electrical output
                                                    data.
------------------------------------------------------------------------
2. Other non-Hg HAP metals....  a. Collect fuel    Procedure in Sec.
                                 samples.           63.10008(c) or ASTM
                                                    D2234/D2234M (for
                                                    coal) or equivalent.
                                b. Composite fuel  Procedure in Sec.
                                 samples.           63.10008(d) or
                                                    equivalent.
                                c. Prepare         EPA SW-846-3020A (for
                                 composited fuel    liquid samples) or
                                 samples.           ASTM D2013/D2013M-
                                                    (for coal) or
                                                    equivalent.
                                d. Determine heat  ASTM D5865 (for coal)
                                 content of the     or equivalent.
                                 fuel type.
                                e. Determine       ASTM D3173 or
                                 moisture content   equivalent.
                                 of the fuel type.
                                f. Measure other   EPA SW-846-6010B or
                                 non-Hg HAP         ASTM D3683 (for coal
                                 metals             samples) or
                                 concentrations     equivalent; EPA SW-
                                 in fuel sample.    846-6010B (for other
                                                    solid fuel samples)
                                                    or equivalent; or
                                                    EPA SW-846-6020 (for
                                                    liquid fuel samples)
                                                    or equivalent.
                                g. Convert         Method 19 F-factor
                                 concentration      methodology at 40
                                 into units of      CFR part 60,
                                 pounds of          Appendix A-7 of this
                                 pollutant per      chapter, or
                                 TBtu of heat       calculate using mass
                                 content or lb      emissions rate and
                                 per MWh.           electrical output
                                                    data.
                                b. Composite fuel  Procedure in Sec.
                                 samples.           63.10008(d) or
                                                    equivalent.
------------------------------------------------------------------------
3. Hydrogen chloride (HCl)....  a. Collect fuel    Procedure in Sec.
                                 samples.           63.10008(c) or D2234/
                                                    D2234M (for coal) or
                                                    equivalent.
                                b. Composite fuel  Procedure in Sec.
                                 samples.           63.10008(d) or
                                                    equivalent.
                                c. Prepare         EPA SW-846-3020A (for
                                 composited fuel    liquid samples), EPA
                                 samples.           SW-846-3050B (for
                                                    solid samples), or
                                                    ASTM D2013/D2013M
                                                    (for coal) or
                                                    equivalent.
                                d. Determine heat  ASTM D5865 (for coal)
                                 content of the     or equivalent.
                                 fuel type.
                                e. Determine       ASTM D3173 or
                                 moisture content   equivalent.
                                 of the fuel type.
                                f. Measure         EPA SW-846-9250 or
                                 chlorine           ASTM D6721 (for
                                 concentration in   coal) or equivalent,
                                 fuel sample.       or EPA SW-846-9250
                                                    or ASTM E776 (for
                                                    solid or liquid
                                                    samples) or
                                                    equivalent.
                                g. Convert         Method 19 F-factor
                                 concentrations     methodology at 40
                                 into units of      CFR part 60,
                                 pounds of          Appendix A-7 of this
                                 pollutant per      chapter, or
                                 MMBtu of heat      calculate using mass
                                 content or lb      emissions rate and
                                 per MWh.           electrical output
                                                    data.
------------------------------------------------------------------------
4. Hydrogen fluoride (HF).....  a. Collect fuel    Procedure in Sec.
                                 samples.           63.10008(c) or D2234/
                                                    D2234M (for coal) or
                                                    equivalent.
                                b. Composite fuel  Procedure in Sec.
                                 samples.           63.10008(d) or
                                                    equivalent.
                                c. Prepare         EPA SW-846-3020A (for
                                 composited fuel    liquid samples), EPA
                                 samples.           SW-846-3050B (for
                                                    solid samples), or
                                                    ASTM D2013/D2013M
                                                    (for coal) or
                                                    equivalent.
                                d. Determine heat  ASTM D5865 (for coal)
                                 content of the     or equivalent.
                                 fuel type.
                                e. Determine       ASTM D3173 or
                                 moisture content   equivalent.
                                 of the fuel type.
                                f. Measure         EPA SW-846-9250 or
                                 chlorine           ASTM D6721 (for
                                 concentration in   coal) or equivalent,
                                 fuel sample.       or EPA SW-846-9250
                                                    or ASTM E776 (for
                                                    solid or liquid
                                                    samples) or
                                                    equivalent.
                                g. Convert         Method 19 F-factor
                                 concentrations     methodology at 40
                                 into units of      CFR part 60,
                                 pounds of          Appendix A-7 of this
                                 pollutant per      chapter.
                                 MMBtu of heat
                                 content.
------------------------------------------------------------------------

    As stated in Sec.  63.10007, you must comply with the following 
requirements for establishing operating limits:

[[Page 25133]]



                       Table 7 to Subpart UUUUU of Part 63--Establishing Operating Limits
----------------------------------------------------------------------------------------------------------------
                                  And your operating                                           According to the
    If you have an applicable      limits are based     You must . . .        Using . . .          following
    emission limit for . . .           on . . .                                                  requirements
----------------------------------------------------------------------------------------------------------------
1. Particulate matter (PM),       a. Wet scrubber     i. Establish a      (1) Data from the   (a) You must
 mercury (Hg), or other non-Hg     operating           site-specific       pressure drop and   collect pressure
 HAP metals.                       parameters.         minimum pressure    liquid flow rate    drop and liquid
                                                       drop and minimum    monitors and the    flow-rate data
                                                       flow rate           PM, Hg, or other    every 15 minutes
                                                       operating limit     non-Hg HAP metals   during the entire
                                                       according to Sec.   performance test.   period of the
                                                         63.10011(c).                          performance
                                                                                               tests;
                                                                                              (b) Determine the
                                                                                               average hourly
                                                                                               pressure drops
                                                                                               and liquid flow
                                                                                               rates for each
                                                                                               individual test
                                                                                               run in the three-
                                                                                               run performance
                                                                                               test by computing
                                                                                               the average of
                                                                                               all the 15-minute
                                                                                               readings taken
                                                                                               during each test
                                                                                               run.
                                  b. Electrostatic    i. Establish a      (1) Data from the   (a) You must
                                   precipitator        site-specific       secondary power     collect secondary
                                   operating           secondary power     input during the    voltage and
                                   parameters          input according     PM, Hg, or other    current and
                                   (option only for    to Sec.             non-Hg HAP metals   calculate total
                                   units that          63.10011(c).        performance test.   ESP secondary
                                   operate wet                                                 power input data
                                   scrubbers).                                                 every 15 minutes
                                                                                               during the entire
                                                                                               period of the
                                                                                               performance
                                                                                               tests;
                                                                                              (b) Determine the
                                                                                               average hourly
                                                                                               total secondary
                                                                                               power inputs for
                                                                                               each individual
                                                                                               test run in the
                                                                                               three-run
                                                                                               performance test
                                                                                               by computing the
                                                                                               average of all
                                                                                               the 15-minute
                                                                                               readings taken
                                                                                               during each test
                                                                                               run.
                                  c. Filterable PM    i. Establish a      (1) Data from the   (a) You must
                                   results obtained    site-specific       PM performance      collect at least
                                   from performance    filterable PM       test.               3 test runs of
                                   testing and are     concentration                           Method 5
                                   measured            according to Sec.                       filterable PM
                                   continuously          63.10011(d).                          results.
                                   using PM CEMS.
----------------------------------------------------------------------------------------------------------------
2. Hydrogen chloride (HCl) or     a. Wet scrubber     i. Establish a      (1) Data from the   (a) You must
 hydrogen fluoride (HF).           operating           site-specific       pH and liquid       collect pH and
                                   parameters.         minimum pH and      flow rate           liquid flow rate
                                                       flow rate           monitors and the    data every 15
                                                       operating limits    HCl performance     minutes during
                                                       according to Sec.   test.               the entire period
                                                         63.10011(c).                          of the
                                                                                               performance
                                                                                               tests;
                                                                                              (b) Determine the
                                                                                               average hourly pH
                                                                                               liquid flow rates
                                                                                               for each
                                                                                               individual test
                                                                                               run in the three-
                                                                                               run performance
                                                                                               test by computing
                                                                                               the average of
                                                                                               all the 15-minute
                                                                                               readings taken
                                                                                               during each test
                                                                                               run.
                                  b. Dry scrubber or  i. Establish a      (1) Data from the   (a) You must
                                   DSI operating       site-specific       sorbent injection   collect sorbent
                                   parameters.         minimum sorbent     rate monitors and   injection rate
                                                       injection rate      HCl or Hg           data every 15
                                                       operating limit     performance test.   minutes during
                                                       according to Sec.                       the entire period
                                                         63.10011(c). If                       of the
                                                       different acid                          performance
                                                       gas sorbents are                        tests;
                                                       used during the                        (b) Determine the
                                                       HCl performance                         average hourly
                                                       test, the average                       sorbent injection
                                                       value for each                          rates of the
                                                       sorbent becomes                         three test run
                                                       the site-specific                       averages measured
                                                       operating limit                         during the
                                                       for that sorbent.                       performance test.
----------------------------------------------------------------------------------------------------------------

    As stated in Sec.  63.10021, you must show continuous compliance 
with the emission limitations for affected sources according to the 
following:

[[Page 25134]]



Table 8 to Subpart UUUUU of Part 63--Demonstrating Continuous Compliance
------------------------------------------------------------------------
     If you must meet the
following operating limits or       You must demonstrate continuous
work practice standards . . .             compliance by . . .
------------------------------------------------------------------------
1. Fabric filter bag leak      Installing and operating a bag leak
 detection operation.           detection system according to Sec.
                                63.10010 and operating the fabric filter
                                such that the requirements in Sec.
                                63.10021(a)(9) are met.
2. Wet PM scrubber pressure    a. Collecting the pressure drop and
 drop and liquid flow-rate.     liquid flow rate monitoring system data
                                according to Sec.  Sec.   63.10010 and
                                63.10020; and
                               b. Reducing the data to 12-hour block
                                averages; and
                               c. Maintaining the 12-hour average
                                pressure drop and liquid flow-rate at or
                                above the operating limits established
                                during the performance test according to
                                Sec.   63.10011(c).
3. Wet acid gas scrubber pH    a. Collecting the pH and liquid flow rate
 and liquid flow rate.          monitoring system data according to Sec.
                                 Sec.   63.10010 and 63.10020; and
                               b. Reducing the data to 12-hour block
                                averages; and
                               c. Maintaining the 12-hour average pH and
                                liquid flow-rate at or above the
                                operating limits established during the
                                performance test according to Sec.
                                63.10011(c).
4. Dry scrubber or DSI         a. Collecting the sorbent or carbon
 sorbent or carbon injection    injection rate monitoring system data
 rate.                          for the dry scrubber or DSI according to
                                Sec.  Sec.   63.10010 and 63.10020; and
                               b. Reducing the data to 12-hour block
                                averages; and
                               c. Maintaining the 12-hour average
                                sorbent or carbon injection rate at or
                                above the operating limit established
                                during the performance test according to
                                Sec.   63.10011(c).
5. Electrostatic precipitator  a. Collecting the secondary power input
 secondary power input.         monitoring system data for the
                                electrostatic precipitator according to
                                Sec.  Sec.   63.10010 and 63.10020; and
                               b. Reducing the data to 12-hour block
                                averages; and
                               c. Maintaining the 12-hour average
                                secondary power input at or above the
                                operating limits established during the
                                performance test according to Sec.
                                63.10011(c).
6. Fuel pollutant content....  a. Only burning the fuel types and fuel
                                mixtures used to demonstrate compliance
                                with the applicable emission limit
                                according to Sec.   63.10011(c) or (d)
                                as applicable; and
                               b. Keeping monthly records of fuel use
                                according to Sec.   63.10021(a).
7. Filterable PM as measured   a. Collecting the PM concentration data
 by PM CEMS.                    using a PM CEMS installed, operated and
                                maintained in accordance with PS 11 at
                                40 CFR part 60, Appendix B of this
                                chapter and QA Procedure 5 at 40 CFR
                                part 60, Appendix F of this chapter;
                               b. Converting hourly emissions
                                concentrations to 30 boiler operating mg/
                                dscm values; and
                               c. Maintaining the 30 boiler operating
                                day rolling average mg/dscm values below
                                the operating limits established during
                                the performance test according to Sec.
                                63.10011(d).
------------------------------------------------------------------------

    As stated in Sec.  63.10031, you must comply with the following 
requirements for reports:

       Table 9 to Subpart UUUUU of Part 63--Reporting Requirements
------------------------------------------------------------------------
                                    The report must      You must submit
     You must submit a(n)            contain . . .      the report . . .
------------------------------------------------------------------------
1. Compliance report..........  a. Information          Semiannually
                                 required in Sec.        according to
                                 63.10031(c)(1)          the
                                 through (11) through    requirements in
                                 (11); and               Sec.
                                                         63.10031(b).
                                b. If there are no
                                 deviations from any
                                 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 8 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 system,
                                 and operating
                                 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); and
                                d. If you had a
                                 startup, shutdown, or
                                 malfunction during
                                 the reporting period
                                 and you took actions
                                 consistent with your
                                 startup, shutdown,
                                 and malfunction plan,
                                 the compliance report
                                 must include the
                                 information in Sec.
                                 63.10(d)(5)(i).

[[Page 25135]]

 
2. An immediate startup,        a. Actions taken for    i. By fax or
 shutdown, and malfunction       the event; and.         telephone
 report if you had a startup,                            within 2
 shutdown, or malfunction                                working days
 during the reporting period                             after starting
 that is not consistent with                             actions
 your startup, shutdown, and                             inconsistent
 malfunction plan, and the                               with the plan;
 source exceeds any applicable                           and
 emission limitation in the
 emission standard.
                                b. The information in   ii. By letter
                                 Sec.                    within 7
                                 63.10(d)(5)(ii).        working days
                                                         after the end
                                                         of the event
                                                         unless you have
                                                         made
                                                         alternative
                                                         arrangements
                                                         with the
                                                         permitting
                                                         authority.
------------------------------------------------------------------------

    As stated in Sec.  63.10040, you must comply with the applicable 
General Provisions according to the following:

     Table 10 to Subpart UUUUU of Part 63--Applicability of General
                       Provisions to Subpart UUUUU
------------------------------------------------------------------------
                                                      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          ..................
                                   Requirements.
63.8(c)(1)(i)...................  General duty to     ..................
                                   minimize
                                   emissions and CMS
                                   operation.
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.
 (d)(1)-(2), (e), and (f).         Reporting
                                   Requirements.
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 25136]]

 
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
                                                       63.10031(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. The monitoring, recordkeeping, and 
reporting provisions of this appendix shall be considered to be met 
to the extent that they have already been, and are continuing to be, 
met or exceeded under another Federal or State program.
    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 the CEMS fails to produce quality-assured Hg mass 
emissions data is counted as an hour of monitoring system downtime.

2. Monitoring of Hg Emissions for Various Configurations

    2.1 Single Unit-Single Stack Configuration. For an affected unit 
that exhausts to the atmosphere through a single, dedicated stack, 
the owner or operator shall install, certify, maintain, and operate 
a Hg CEMS or a sorbent trap monitoring system and any other 
necessary monitoring components needed to express the measured Hg 
emissions in the units of the applicable emissions standard, in 
accordance with section 3.2 of this appendix.
    2.2 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, the owner or operator 
shall either:
    2.2.1 Install, certify, maintain, and operate the monitoring 
systems described in paragraph 2.1 of this section in the duct to 
the common stack from each unit; or
    2.2.2 Install, certify, maintain, and operate the monitoring 
systems described in paragraph 2.1 of this section in the common 
stack.
    2.3 Unit Utilizing Common Stack with Non-affected Units. When 
one or more affected units shares a common stack with one or more 
non-affected units, the owner or operator shall either:
    2.3.1 Install, certify, maintain, and operate the monitoring 
systems described in paragraph 2.1 of this section in the duct to 
the common stack from each affected unit; or
    2.3.2 Install, certify, maintain, and operate the monitoring 
systems described in paragraph 2.1 of this section in the common 
stack and attribute all of the Hg emissions measured at the common 
stack to the affected unit(s).
    2.4 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, the owner and operator shall either:
    2.4.1 Install, certify, maintain, and operate the monitoring 
systems described in paragraph 2.1 of this section on both the main 
stack and the bypass stack; or
    2.4.2 Install, certify, maintain, and operate the monitoring 
systems described in paragraph 2.1 of this section only on the main 
stack, and report the maximum potential Hg concentration (as defined 
in section 3.2.1.4.1 of this appendix) for each unit operating hour 
in which the bypass stack is used.
    2.5 Unit with Multiple Stack or Duct Configuration. If the flue 
gases from an affected unit either: are discharged to the atmosphere 
through more than one stack; or are fed into a single stack through 
two or more ducts and the owner or operator chooses to monitor in 
the ducts rather than in the stack, the owner or operator shall 
either:
    2.5.1 Install, certify, maintain, and operate the monitoring 
systems described in paragraph 2.1 of this section in each of the 
multiple stacks; or
    2.5.2 Install, certify, maintain, and operate the monitoring 
systems described in paragraph 2.1 of this section in each of the 
ducts that feed into the stack.

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 (Hg\0\, 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 Hg\0\ 
converter, sample transport, sample conditioning, flow control/gas 
manifold, gas analyzer, and data acquisition and handling system 
(DAHS).
    3.1.2 Sorbent Trap Monitoring System means the equipment 
required to monitor Hg emissions continuously, 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 rate 
proportional to the stack gas volumetric flow

[[Page 25137]]

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 known concentration of a gaseous species that is produced 
and certified in accordance with an EPA traceability protocol.
    3.1.7 Span value means a conservatively high estimate of the gas 
concentrations or stack gas flow rates to be measured by a CEMS. For 
a Hg pollutant concentration monitor, the span value should be set 
to approximately twice the concentration corresponding to the 
emission standard, rounded off as appropriate.
    3.1.8 Zero-Level Gas means calibration gas with a concentration 
that is below the level detectable by a gas monitoring system.
    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 either to 
assess the ability of a gas monitor to measure the concentrations of 
calibration gases accurately, or the ability of a flow monitor to 
read electronic reference signals accurately. A zero-level gas (or 
signal) and an upscale gas (or signal) are required for this test. 
For gas monitors, either a mid-level gas or a high-level gas may be 
used. For a flow monitor, an upscale signal of 50 to 70 percent of 
the calibration span value is required. For a Hg CEMS, the upscale 
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 gas analyzer is linear across its 
measurement range. Three calibration gas standards (i.e., low, mid, 
and high-level gases) are required for this test. For a Hg CEMS, 
elemental Hg calibration standards are required.
    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 gas monitor, 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. For a Hg CEMS, 
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 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 Unit Operating Day means a calendar day in which a unit 
combusts any fuel.
    3.1.20 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 25138]]

[GRAPHIC] [TIFF OMITTED] TP03MY11.030

    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, 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 may 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 
monitor 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 a converter, to a by-pass valve (for Hg speciating 
systems), or to 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 Hg\0\ and HgCl2 are 
required. Special reagents and equipment may be needed to prepare 
the Hg\0\ 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 detectable limit of the 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 25139]]

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 represents the emissions exiting to the atmosphere; 
and at which 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 [micro]g/scm for all coal ranks (including coal refuse) 
except for lignite; for lignite, use 16 [micro]g/scm. 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. If different coals are blended as part 
of normal operation, use the highest MPC for any fuel in the blend. 
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 [micro]g/scm, use the result as the span value. 
Otherwise, round off the result to the next highest integer. 
Alternatively, you may round off the span value to the next highest 
multiple of 10 [micro]g/scm.
    3.2.1.4.3 Full-Scale Range. The full-scale range of the Hg 
analyzer output must include 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 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 Monitoring Systems. When the applicable Hg 
emission limit is specified in units of lb/TBtu or lb/GWh, some or 
all of the monitoring systems described in paragraphs 3.2.3.1 and 
3.2.3.2 of this section will be needed to convert the measured Hg 
concentrations to the units of the emissions standard. These 
additional monitoring systems shall be installed, certified, 
maintained, operated, and quality-assured according to the 
applicable provisions of this appendix (see section 4.1.3 of this 
appendix). 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 (e.g., 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 accounted for, as 
follows:
    3.2.3.1.1 Determine the stack gas moisture content using a 
certified continuous moisture monitoring system; or
    3.2.3.1.2 Use the moisture value determined during the most 
recent Hg emissions test while combusting the fuel type currently in 
use; or
    3.2.3.1.3 For coal combustion, use a fuel-specific moisture 
default value. For anthracite coal, use 3.0% H2O; for 
bituminous coal, use 6.0% H2O; for sub-bituminous coal, 
use 8.0% H2O; and for lignite, use 11.0% H2O.
    3.2.3.2 Electrical Output-Based Emission Rates. If the 
applicable Hg limit is electrical output-based (e.g., lb/GWh), 
hourly electrical load data and unit operating times are required in 
addition to hourly data from a certified flow rate monitor and (if 
applicable) moisture data.
    3.2.3.3 Span and Range of Flow Rate, Diluent Gas, and Moisture 
Monitors. Set the span value of a CO2 or O2 
monitor at 1.00 to 1.25 times the maximum potential concentration. 
Set the span value of a flow rate monitor at 1.00 to 1.25 times the 
maximum potential flow rate, in units of standard cubic feet per 
hour (scfh). If the units of measure for daily calibrations of the 
flow monitor are not expressed in scfh, convert the calculated span 
value from scfh to an equivalent ``calibration span value'' in the 
units of measure actually used for daily calibrations. Set the full-
scale range of the CO2, O2, and flow monitors 
such that the majority of the data will fall between 20 and 80% of 
full-scale. For a continuous moisture sensor, there is no span value 
requirement; set up and operate the instrument according to the 
manufacturer's instructions.

4. Certification and Recertification Requirements

    4.1 Certification Requirements. All Hg CEMS and sorbent trap 
systems and the monitoring systems used to continuously measure Hg 
emissions in units of the applicable emissions standard in 
accordance with this appendix must be certified prior to the 
applicable compliance date specified in Sec.  63.9984.
    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.
    4.1.1.1 7-Day Calibration Error Test. Perform the 7-day 
calibration error test on 7 consecutive 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 each monitor 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.

[[Page 25140]]



               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\.....  [verbar] R-A [verbar]    [verbar] R-A [verbar]    The alternate
                                        <= 5.0% of span value,   <= 1.0 [mu]g/scm.        specification may be
                                        for both the zero and                             used on any day of the
                                        upscale gases, on each                            test.
                                        of the 7 days.
Linearity check \3\..................  [verbar] R-Aavg          [verbar] R-Aavg          The alternate
                                        [verbar] <= 10.0% of     [verbar] <= 0.8 [mu]g/   specification may be
                                        the reference gas        scm.                     used at any gas level.
                                        concentration at each
                                        calibration gas level.
3-level system integrity check \4\...  [verbar] R-Aavg          [verbar] R-Aavg          The alternate
                                        [verbar] <= 10.0% of     [verbar] <= 0.8 [mu]g/   specification may be
                                        the reference gas        scm.                     used at any gas level.
                                        concentration at each
                                        calibration gas level.
RATA.................................  20.0% RA...............  [verbar] RMavg-Cavg      RMavg < 5.0 [mu]g/scm.
                                                                 [verbar] <= 1.0 [mu]g/
                                                                 scm **.
Cycle time test \2\                    15 minutes.\5\.........
----------------------------------------------------------------------------------------------------------------
\1\ Note that [verbar] R-A [verbar] is the absolute value of the difference between the reference gas value and
  the analyzer reading. [verbar] R-Aavg [verbar] 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.
\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 [mu]g/m\3\, for 2 minutes.
** Note that [verbar] RMavg-Cavg [verbar] 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 -.

    4.1.1.2 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 each monitor at its normal operating temperature 
and conditions. 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. 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 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-2. (Note: This test is not required if the CEMS does not have a 
converter).
    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 [mu]g/scm (whichever 
is less restrictive) for two minutes.
    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 (the Ontario Hydro Method) and Methods 
29, 30A, and 30B in appendix A-8 to part 60 of this chapter. When 
Method 29 or the Ontario Hydro Method is used, paired sampling 
trains are required. To validate a Method 29 or Ontario Hydro 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 [mu]g/dscm. If the average concentration is 
<=1.0 [mu]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 0.03 [mu]g/dscm. If the RD 
specification is met, the results of the two samples shall be 
averaged arithmetically.
[GRAPHIC] [TIFF OMITTED] TP03MY11.031

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. Special Considerations. A 
minimum of nine valid test runs must be performed, directly 
comparing the CEMS measurements to the reference method. If 12 or 
more runs are performed, you may discard the results from a maximum 
of three runs for calculating relative accuracy. The minimum time 
per run is 21 minutes if Method 30A is used. If the Ontario Hydro 
Method, Method 29, or Method 30B 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 the Ontario 
Hydro Method or Method 29 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 [mu]g/scm basis, as 
described in section 12 of Performance Specification 2 or 6 in 
Appendix B to part 60 of this chapter. The CEMS must either meet the 
main performance specification or the alternative specification in 
Table A-1.

[[Page 25141]]

    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 system are listed in paragraph 4.1.1.5 of 
this section.
    4.1.2.2 Special Considerations. The special considerations 
specified in paragraph 4.1.1.5.1 of this section apply to the RATA 
of a sorbent trap monitoring system. During the RATA, the monitoring 
system must be operated and quality-assured in accordance with 
Performance Specification 12B in Appendix B to part 60 of this 
chapter. 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.
    4.1.2.3 Calculation of RATA Results. Calculate the relative 
accuracy (RA) of the Hg concentration monitoring system, on a 
[micro]g/scm basis, as described in section 12 of Performance 
Specification 2 or 6 in appendix B to part 60 of this chapter. The 
main and alternative RATA performance specifications in Table A-1 
for Hg CEMS also apply to the sorbent trap monitoring system.
    4.1.2.4 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 and/or diluent gas concentration and/or stack 
gas moisture content in order to convert Hg concentration data to 
units of the applicable emission limit must be certified. The 
minimum certification test requirements and performance 
specifications for these systems are shown in Table A-2, below.
    4.2 Recertification. Whenever the owner or operator makes a 
replacement, modification, or change to a certified Hg CEMS, sorbent 
trap monitoring system, flow rate monitoring system, diluent gas 
monitoring system, or moisture monitoring system that may 
significantly affect the ability of the system to accurately measure 
or record the Hg concentration, stack gas volumetric flow rate, 
CO2 concentration, O2 concentration, 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 flow 
or concentration 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.

   Table A-2--Minimum Required Certification Tests and Performance Specifications for Other Monitoring Systems
----------------------------------------------------------------------------------------------------------------
                                                                                              And the conditions
                                   Of this auxiliary       The main          The alternate     of the alternate
 For this required certification   monitoring system      performance         performance      specification are
           test . . .                    . . .         specification \1\   specification \2\         . . .
                                                           is . . .            is . . .
----------------------------------------------------------------------------------------------------------------
7-day calibration error test....  O2 or CO2.........  [bond] R - A                            ..................
                                                       [bond] <= 0.5% O2
                                                       or CO2 for both
                                                       the zero and
                                                       upscale gases, on
                                                       each day of the
                                                       test.
7-day calibration error test....  Flow rate.........  [bond] R -A [bond]  [bond] R - A        The alternate
                                                       <= 3.0% of          [bond] <= 0.01      specification may
                                                       calibration span    in. H2O, for DP-    be used on any
                                                       value for both      type monitors.      day of the tests.
                                                       the zero and
                                                       upscale signals,
                                                       on each day of
                                                       the test.
Linearity check.................  O2 or CO2.........  [bond] R - Aavg     [bond] R -A [bond]  The alternate
                                                       [bond] <= 5.0% of   <= 0.5% O2 or CO2.  specification may
                                                       the reference gas                       be used at any
                                                       value.                                  gas level.
Cycle time test.................  O2 or CO2.........  <= 15 minutes.                          ..................
RATA............................  O2 or CO2.........  10.0% RA..........  [bond] RMavg -      ..................
                                                                           Cavg [bond] <=
                                                                           1.0% O2 or % CO2.
RATA............................  Flow rate.........  10.0% RA.                               ..................
RATA............................  Moisture..........  10.0% RA..........  [bond] RMavg -      ..................
                                                                           Cavg [bond] <=
                                                                           1.5% H2O.
----------------------------------------------------------------------------------------------------------------
\1\ Note that [bond] R -A [bond] is the absolute value of the difference between the reference gas value and the
  analyzer reading. [bond] R - Aavg [bond] 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\ Note that [bond] RMavg - Cavg [bond] 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 -.

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-3, below.
    5.1.2 Test Frequency. The frequency for the required QA tests of 
the Hg CEMS shall be as follows:
    5.1.2.1 Perform calibration error tests of the Hg CEMS daily. 
Use either NIST-traceable elemental Hg standards or NIST-traceable 
oxidized Hg standards for these calibrations. 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.

[[Page 25142]]



                              Table A-3--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    [bond] R - A [bond] <=
                                                                 mid- or high- level      5.0% of span value; or
                                                                 gas.                     [bond] R - A [bond] <=
                                                                                          1.0 [mu]g/scm.
                                                                 Use either
                                                                 elemental or oxidized
                                                                 Hg.
                                                                 Calibrations
                                                                 are not required when
                                                                 the unit is not in
                                                                 operation.
Single-level system integrity check..  Weekly \1\.............   Required only   [bond] R - Aavg [bond]
                                                                 for systems with         <= 10.0% of the
                                                                 converters.              reference gas value;
                                                                                          or
                                                                                         [bond] R - Aavg [bond]
                                                                                          <= 0.8 [mu]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 or 3-level system      Quarterly \3\..........   Required in     [bond] R - Aavg [bond]
 integrity check.                                                each ``QA operating      <= 10.0% of the
                                                                 quarter'' \2\--and no    reference gas value,
                                                                 less than once every 4   at each calibration
                                                                 calendar quarters.       gas level; or [bond] R
                                                                                          - Aavg [bond] <= 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; or [bond]
                                                                 may be extended for      RMavg - Cavg [bond] <=
                                                                 ``non-QA operating       1.0 [mu]g/scm; if
                                                                 quarters,'' up to a      RMavg < 5.0 [mu]g/scm.
                                                                 maximum of 8 quarters
                                                                 from the quarter of
                                                                 the previous test.
                                                                 720 operating
                                                                 hour grace period
                                                                 available.
----------------------------------------------------------------------------------------------------------------
\1\ ``Weekly'' means once every 168 unit operating hours.
\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.

    5.1.2.3 A weekly single-level system integrity check (if 
required--see third column in Table A-3).
    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 stac operating hour grace period 
following that quarter.
    5.1.3 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 of the acceptance criteria for the required QA 
tests in Table A-3 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.
    5.1.4 Grace Periods.
    5.1.4.1 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.
    5.1.4.2 A 720 unit or stack operating hour grace period is 
available for RATAs of the Hg CEMS.
    5.1.4.3 There is no grace period for weekly system integrity 
checks. The test must be completed once every 168 unit or stack 
operating hours.
    5.1.5 Adjustment of Span. If the Hg concentration readings 
exceed the span value for a significant percentage of the unit 
operating hours in a calendar quarter, make any necessary 
adjustments to the MPC and span value. 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 
12B (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.
    5.2.2.2 The same RATA performance criteria specified in Table A-
3 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.
    5.2.2.4 Data validation for RATAs of the system shall be done in 
accordance with paragraph 5.1.3 of this section.
    5.3 Flow Rate, Diluent Gas, and Moisture Monitoring Systems. The 
minimum on-going QA test requirements for these monitoring systems 
are summarized in Table A-4, below. The data validation provisions 
in paragraph 5.1.3 apply to these systems. The linearity grace 
period described in paragraph 5.1.4.1 applies to the O2 
and CO2 monitors. The RATA grace period in paragraph 
5.1.4.2 of this section applies to the O2, 
CO2, moisture, and flow rate monitors.
    5.4 QA/QC Program for Continuous Monitoring Systems. The owner 
or operator shall develop and implement a quality assurance/quality 
control (QA/QC) program for all continuous monitoring systems that

[[Page 25143]]

are used to provide data under this subpart (i.e., all Hg CEMS, 
sorbent trap monitoring systems, and any associated monitoring 
systems used to convert Hg concentration data to the appropriate 
units of measure). 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.

        Table A-4--Minimum On-Going Quality Assurance Test Requirements for Auxiliary Monitoring Systems
----------------------------------------------------------------------------------------------------------------
                                       For this                               With these
   Perform this QA test . . .      monitoring system   At this frequency    conditions and      The acceptance
                                         . . .               . . .         exceptions . . .   criteria are . . .
----------------------------------------------------------------------------------------------------------------
Calibration error test..........  O2 or CO2.........  Daily.............   Use        [bond] R - A
                                                                           either a mid or     [bond] <= 1.0% O2
                                                                           high level gas.     or CO2.
                                                                           Not
                                                                           required on non-
                                                                           operating days.
Calibration error test..........  Flow rate.........  Daily.............   Not        [bond] R - A
                                                                           required on non-    [bond] <= 6.0% of
                                                                           operating days.     calibration span
                                                                                               value or [bond] R
                                                                                               - A [bond] <=
                                                                                               0.02 in. H2O for
                                                                                               a DP-type
                                                                                               monitor.
Interference check..............  Flow rate.........  Daily.............   Not        Must be passed.
                                                                           required on non-
                                                                           operating days.
Linearity check.................  O2 or CO2.........  Quarterly.........   Required   [bond] R - A
                                                                           in each QA          [bond] <= 5.0% of
                                                                           operating           reference gas or
                                                                           quarter--but no     [bond] R - A
                                                                           less than once      [bond] <= 1.0% O2
                                                                           every 4 calendar    or CO2.
                                                                           quarters.
                                                                           168
                                                                           operating hour
                                                                           grace period
                                                                           available.
Leak check......................  Flow rate.........  Quarterly.........   Required   Must be passed.
                                                                           only for DP-type
                                                                           flow monitors.
RATA............................  O2 or CO2.........  Annual ***........   Once       RA <= 7.5%; or
                                                                           every four QA       [bond] RMavg -
                                                                           operating           Cavg [bond] <=
                                                                           quarters, not to    0.7% O2 or CO2.
                                                                           exceed 8 calendar
                                                                           quarters.
RATA............................  Flow rate.........  Annual ***........   Once       RA <= 7.5%.
                                                                           every four QA
                                                                           operating
                                                                           quarters, not to
                                                                           exceed 8 calendar
                                                                           quarters.
RATA............................  Moisture..........  Annual ***........   Once       RA <= 7.5%; or
                                                                           every four QA       [bond] RMavg -
                                                                           operating           Cavg [bond] <=
                                                                           quarters, not to    1.0% H2O.
                                                                           exceed 8 calendar
                                                                           quarters.
----------------------------------------------------------------------------------------------------------------
*** Note that these RATAs can still be passed at RA percentages up to and including 10.0% RA. Alternate
  specifications of [bond] R - A [bond] <= 1.0% O2 or CO2 and [bond] R - A [bond] <= 1.5% H2O are also
  acceptable. However, for all of these acceptance criteria, the test frequency becomes semiannual (i.e., once
  every two QA operating quarters) monitors. The RATA grace period in paragraph 5.1.4.2 of this section applies
  to the O2, CO2, and flow rate monitors.

    5.4.1 General Requirements.
    5.4.1.1 Preventive Maintenance. Keep a written record of 
procedures needed to maintain the monitoring system 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.
    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 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 recorded (e.g., changing 
of flow monitor polynomial coefficients or K factors, changing the 
dilution ratio of a gas monitor, etc.), and a written explanation of 
the procedures used to make the adjustment(s) shall be kept.
    5.4.2 Specific Requirements for Hg CEMS, Flow Rate, Diluent Gas, 
and Moisture Monitoring Systems.
    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 and all associated monitoring 
systems. If moisture and/or chlorine is added to the Hg calibration 
gas, explain how the dilution effect of the moisture and/or chlorine 
addition on the calibration gas concentration is accounted for. Also 
keep records of the procedures used to perform linearity checks (of 
the Hg CEMS and, if applicable, the CO2 or O2 
monitor) and the procedures for system integrity checks of the Hg 
CEMS. Explain how the test results are calculated and evaluated.
    5.4.2.2 Monitoring System Adjustments. Explain how each 
component of the continuous emission monitoring system will be 
adjusted to provide correct responses to calibration gases or 
reference signals 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 monitoring systems. Indicate the 
reference methods used and explain 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 tracking 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. Explain 
the procedures used to perform the leak checks when a sorbent trap 
is placed in service and removed from service. Also explain 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

[[Page 25144]]

control criteria in Table 12B-1 in section 9.0 of Performance 
Specification 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 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. Include in the discussion 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 and (as applicable) flow 
rate, diluent gas, and moisture monitoring systems 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.
    6.1.4 Operating hours in which valid data are not obtained, 
either for Hg concentration or for another parameter, are considered 
to be hours of monitor downtime.
    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.
    6.2.1.3 Multiply the lb/MMBtu value obtained in section 6.2.1.2 
of this appendix by 10\6\ to convert it to lb/TBtu.
    6.2.1.4 If the heat input-based Hg emission rate limit must be 
met over a specified averaging period (e.g., a 30 boiler operating 
day rolling average), use Equation 19-19 in EPA Method 19 to 
calculate the Hg emission rate for each averaging period. 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 First, 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] TP03MY11.032

Where:

Mh = Hg mass emissions for the hour (lb)
K = Units conversion constant, 6.236 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)
th = Unit or stack operating time, fraction of the clock 
hour, expressed as a decimal. For example, th = 1.00 for 
a full operating hour, 0.50 for 30 minutes of operation, 0.00 for a 
non-operating hour, etc.) or
[GRAPHIC] [TIFF OMITTED] TP03MY11.033

Where:

Mh = Hg mass emissions for the hour (lb)
K = Units conversion constant, 6.236 x 10-11 lb-scm/
[mu]g-scf
Ch = Hourly average Hg concentration, dry basis 
([micro]g/dscm)
Qh = Stack gas volumetric flow rate for the hour (scfh). 
(Note: Use unadjusted flow rate values; bias adjustment is not 
required)
th = Unit or stack operating time, fraction of the clock 
hour, expressed as a decimal. For example, th = 1.00 for 
a full operating hour, 0.50 for 30 minutes of operation, 0.00 for a 
non-operating hour, etc.)
Bws = Moisture fraction of the stack gas, expressed as a 
decimal (equal to %H2O/100)

    6.2.2.2 Next, 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] TP03MY11.034

Where:

Eho = Electrical output-based Hg emission rate (lb/GWh)
Mh = Hg mass emissions for the hour, from Equation A-2 or 
A-3 of this section, as applicable (lb)
(MW)h = Electrical load for the hour, in megawatts (MW)
th = Unit or stack operating time, fraction of the hour, 
expressed as a decimal. For example, th = 1.00 for a full 
operating hour, 0.50 for 30 minutes of operation, etc.)
10\3\ = Conversion factor from megawatts to gigawatts

    6.2.2.3 If the electrical output-based Hg emission rate limit 
must be met over a specified averaging period (e.g., a 30 boiler 
operating day rolling average), use Equation A-5 of this section to 
calculate the Hg emission rate for each averaging period.

[[Page 25145]]

[GRAPHIC] [TIFF OMITTED] TP03MY11.035

`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. The owner or operator shall, for 
each affected unit and each non-affected unit under section 2.3 of 
this appendix, 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. The file 
shall contain the information in paragraphs 7.1.1 through 7.1.10 of 
this section.
    7.1.1 Monitoring Plan Records. The owner or operator of an 
affected unit shall prepare and maintain a monitoring plan for each 
affected unit or group of units monitored at a common stack and each 
non-affected unit under section 2.3 of this appendix. The monitoring 
plan shall contain sufficient information on the continuous 
monitoring systems that provide data under this subpart, and how the 
data derived from these systems are sufficient to demonstrate 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 the Hg CEMS, 
sorbent trap monitoring systems, and any flow rate and/or moisture, 
and/or diluent gas monitors used to provide data under this subpart, 
the monitoring plan shall contain the following information, as 
applicable:
    7.1.1.2.1 Electronic. Unit or stack IDs; monitoring location(s); 
type(s) of fuel combusted; type(s) of emission controls; maximum 
rated unit heat input(s); megawatt rating(s); monitoring 
methodologies used; monitoring system information (unique system and 
component ID numbers, parameters monitored); formulas used to 
calculate emissions and heat input; unit operating ranges and normal 
load level(s); monitor span and range information.
    7.1.1.2.2 Hard Copy. Schematics and/or blueprints showing the 
location of monitoring systems 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 each non-affected unit under section 2.3 of this 
appendix, 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:
    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 MWge);
    7.1.2.4 The hourly heat input rate (MMBtu/hr, rounded to the 
nearest tenth);
    7.1.2.5 An identification code for the formula used to calculate 
the hourly heat input rate, as provided in the monitoring plan; and
    7.1.2.6 The F-factor used for the heat input rate calculation.
    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 the nearest 
tenth);
    7.1.3.4 A special code, indicating whether or not a quality-
assured Hg concentration is obtained for the hour; and
    7.1.3.5 Monitor availability, as a percentage of unit or stack 
operating hours.
    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 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 the nearest 
tenth). 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 12B 
in Appendix B to part 60 of this chapter; and
    7.1.4.8 Data availability, as a percentage of unit or stack 
operating hours.
    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 12B in Appendix B to part 60 of this chapter). Stack 
gas flow rate data are also needed in order to demonstrate 
compliance with heat input-based and electrical output-based Hg 
emissions limits, as provided in sections 6.2.1 and 6.2.2 of this 
appendix.
    7.1.5.2 For each affected unit or common stack, if measurements 
of stack gas flow rate are required, use a certified flow rate 
monitor to record the following information for each unit or stack 
operating hour:
    7.1.5.2.1 The date and hour;
    7.1.5.2.2 Monitoring system and component identification codes, 
as provided in the monitoring plan, if a quality-assured flow rate 
value is obtained for the hour;
    7.1.5.2.3 The hourly average volumetric flow rate, if a quality-
assured flow rate value is obtained for the hour (in scfh, rounded 
to the nearest thousand);
    7.1.5.2.4 A special code, indicating whether or not a quality-
assured flow rate value is obtained for the hour; and
    7.1.5.2.5 Monitor availability, as a percentage of unit or stack 
operating hours.
    7.1.6 Records of Stack Gas Moisture Content.
    7.1.6.1 Correction of Hg concentration data for moisture is 
sometimes required, when compliance with an applicable Hg emissions 
limit must be demonstrated, as provided in sections 6.2.1 and 6.2.2 
of this appendix. In particular, these corrections are required for 
sorbent trap monitoring systems and for Hg CEMS that measure Hg 
concentration on a dry basis.
    7.1.6.2 If moisture corrections are required, use a certified 
moisture monitoring system to record the following information for 
each unit or stack operating hour (except

[[Page 25146]]

where a default moisture value is used; in that case, keep a record 
of the default value currently in use):
    7.1.6.2.1 The date and hour;
    7.1.6.2.2 Monitoring system and component identification codes 
for the system, as provided in the monitoring plan, if a quality-
assured moisture value is obtained for the hour;
    7.1.6.2.3 Hourly average moisture content of the flue gas 
(percent H2O, rounded to the nearest tenth). If the 
continuous moisture monitoring system consists of wet- and dry-basis 
oxygen analyzers, also record both the wet- and dry-basis oxygen 
hourly averages (in percent O2, rounded to the nearest 
tenth);
    7.1.6.2.4 A special code, indicating whether or not a quality-
assured moisture value is obtained for the hour; and
    7.1.6.2.5 Monitor availability, as a percentage of unit or stack 
operating hours.
    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 (e.g., in units of lb/TBtu), hourly measurements of 
CO2 or O2 concentration are required, in order 
to calculate hourly heat input values.
    7.1.7.2 For each affected unit or common stack, if measurements 
of diluent gas concentration are required, use a certified 
CO2 or O2 monitor to record the following 
information for each unit or stack operating hour:
    7.1.7.2.1 The date and hour;
    7.1.7.2.2 Monitoring system and component identification codes, 
as provided in the monitoring plan, if a quality-assured 
O2 or CO2 concentration is obtained for the 
hour;
    7.1.7.2.3 The hourly average O2 or CO2 
concentration (in percent, rounded to the nearest tenth);
    7.1.8.2.4 A special code, indicating whether or not a quality-
assured O2 or CO2 concentration value is 
obtained for the hour; and
    7.1.7.2.5 Monitor availability, as a percentage of unit or stack 
operating hours.
    7.1.8 Hg Mass Emissions Records. When compliance with a Hg 
emission limit in units of lb/GWh is required, Hg mass emissions 
must be calculated. In such cases, record the following information 
for each operating hour of affected unit or common stack:
    7.1.8.1 The date and hour;
    7.1.8.2 The calculated hourly Hg mass emissions, from Equation 
A-2 or A-3 in section 6.2.2 of this appendix (lb, rounded to three 
decimal places), if valid values of Hg concentration, stack gas 
volumetric flow rate, and (if applicable) moisture data are all 
obtained for the hour;
    7.1.8.3 An identification code for the formula (either Equation 
A-2 or A-3 in section 6.2.2 of this appendix) used to calculate 
hourly Hg mass emissions from Hg concentration, flow rate and (if 
applicable) moisture data; and
    7.1.8.4 A code indicating that the Hg mass emissions were not 
calculated for the hour, if valid data for Hg concentration, flow 
rate, and/or moisture (as applicable) are not obtained for the hour.
    7.1.9 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:
    7.1.9.1 The date and hour;
    7.1.9.2 The hourly Hg emissions rate (lb/TBtu or lb/GWh, as 
applicable, rounded to three decimal places), 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;
    7.1.9.3 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
    7.1.9.4 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.
    7.1.10 Certification and Quality Assurance Test Records. For the 
continuous monitoring systems used to provide data under this 
subpart at each affected unit (or group of units monitored at a 
common stack) and each non-affected unit under section 2.3 of this 
appendix, record the following certification and quality-assurance 
information:
    7.1.10.1 The reference values, monitor responses, and calculated 
calibration error (CE) values, for all required 7-day calibration 
error tests and daily calibration error tests of all volumetric flow 
rate monitors and gas monitors, including Hg CEMS;
    7.1.10.2 The results (pass/fail) of the required daily 
interference checks of flow monitors;
    7.1.10.3 The reference values, monitor responses, and calculated 
linearity error (LE) or system integrity error (SIE) values for all 
required linearity checks of all gas monitors, including Hg CEMS, 
and for all single-level and 3-level system integrity checks of Hg 
CEMS;
    7.1.10.4 The results (pass/fail) of all required quarterly leak 
checks of all differential pressure-type flow monitors (if 
applicable);
    7.1.10.5 The CEMS and reference method readings for each test 
run and the calculated relative accuracy results for all RATAs of 
all Hg CEMS, sorbent trap monitoring systems, and (as applicable) 
flow rate, diluent gas, and moisture monitoring systems;
    7.1.10.6 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 all gas monitors, including Hg CEMS;
    7.1.10.7 Supporting information for all required RATAs of 
volumetric flow rate monitoring systems, diluent gas monitoring 
systems, and moisture monitoring systems, including the raw field 
data and, as applicable, the results of reference method bias and 
drift checks, calibration gas certificates, the results of lab 
analyses, and records of sampling equipment calibrations. For the 
RATAs of Hg CEMS and sorbent trap monitoring systems, keep 
sufficient records of the test dates, the raw reference method and 
monitoring system data, and the results of sample analyses to 
substantiate the reported test results; and
    7.1.10.8 For sorbent trap monitoring systems, 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 12B in Appendix B to 
part 60 of this chapter.
    7.2 Reporting Requirements.
    7.2.1 General Reporting Provisions. The owner or operator shall 
comply with the following reporting requirements for each affected 
unit (or group of units monitored at a common stack) and each non-
affected unit under section 2.3 of this appendix:
    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. In addition to the notifications required 
elsewhere in this subpart, the owner or operator of any affected 
unit shall provide the following notifications for each affected 
unit (or group of units monitored at a common stack) and each non-
affected unit under section 2.3 of this appendix. Provide each 
notification at least 21 days prior to the event:
    7.2.2.1 The date(s) of the required annual RATAs of the Hg CEMS, 
sorbent trap monitoring systems, and (as applicable) flow rate, 
diluent gas, and moisture monitoring systems used to provide data 
under this subpart;
    7.2.2.2 The date on which emissions first exhaust through a new 
stack or flue gas desulfurization system; and
    7.2.2.3 The date on which an affected unit is removed from 
service and placed into long-term cold storage, and the date on 
which the unit is expected to resume operation.
    7.2.3 Monitoring Plan Reporting. The owner or operator of any 
affected unit shall make electronic and hard copy monitoring plan 
submittals for each affected unit (or group of units monitored at a 
common stack) and each non-affected unit under section 2.3 of this 
appendix, as follows:
    7.2.3.1 At least 21 days prior to the initial certification 
testing or recertification testing of a monitoring system used to 
provide data under this subpart; and
    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 update must be submitted either prior to 
or concurrent with the quarterly report for the calendar quarter in 
which the update is required.
    7.2.4 The results of all required certification, 
recertification, and quality-

[[Page 25147]]

assurance tests described in paragraphs 7.1.10.3 through 7.1.10.6 of 
this section shall be submitted electronically, either prior to or 
concurrent with the relevant quarterly electronic report.
    7.2.5 Quarterly Reports.
    7.2.5.1 Beginning with the calendar quarter containing the 
program start date, the owner or operator of any affected unit shall 
submit electronic quarterly reports to the Administrator, in a 
format specified by the Administrator, for each affected unit (or 
group of units monitored at a common stack) and each non-affected 
unit under section 2.3 of this appendix.
    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 7.1.19 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 and 
daily flow monitor interference checks, as described in paragraphs 
7.1.10.1 and 7.1.10.2 of this section.
    7.2.5.4 Information which is incompatible with electronic 
reporting (e.g., field data sheets, lab analyses, stratification 
test results, sampling equipment calibrations, quality control plan 
information) is excluded from electronic reporting.
    7.2.5.5 Compliance Certification. The owner or operator shall 
submit a compliance certification in support of each electronic 
quarterly emissions monitoring report, based on reasonable inquiry 
of those persons with primary responsibility for ensuring that all 
Hg emissions from the affected unit(s) and (if applicable) any non-
affected unit(s) under section 2.3 of this appendix have been 
correctly and fully monitored. The compliance certification shall 
indicate whether the monitoring data submitted were recorded in 
accordance with the applicable requirements of this appendix.
[FR Doc. 2011-7237 Filed 5-2-11; 8:45 am]
BILLING CODE 6560-50-P