[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
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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.
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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.
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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
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Examples of
Category NAICS code \1\ potentially regulated
entities
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Industry...................... 221112 Fossil fuel-fired
electric utility
steam generating
units.
Federal government............ \2\ 221122 Fossil fuel-fired
electric utility
steam generating
units owned by the
Federal government.
State/local/tribal government. \2\ 221122 Fossil fuel-fired
electric utility
steam generating
units owned by
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).
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\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).
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Congress established a specific structure for determining whether
to regulate EGUs under section 112.\5\ Specifically, Congress enacted
CAA section 112(n)(1).
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\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).
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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.
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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).
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\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.
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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.
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\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.
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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.
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\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.
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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.
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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.
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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.
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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.
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\15\ Federal Implementation Plans To Reduce Interstate Transport
of Fine Particulate Matter and Ozone. Proposed Rule. August 2, 2010.
75 FR 45,210.
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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.
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\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.
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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.
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\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.
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\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.
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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.
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\19\ Mercury Study Report to Congress, Vol. I, Pg. 6, December
1997.
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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.
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\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.
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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.
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\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.
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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.
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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.
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\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.
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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.
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\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.
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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\
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\35\ EPA, 2001.
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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.
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\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.
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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\
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\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.
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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.
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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.
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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.
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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.
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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.
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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.
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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.
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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.
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\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.
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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.
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\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.
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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.
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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.
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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.
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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.
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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.
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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\
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\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
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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).
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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\
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\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.
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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\
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\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).
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[[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.
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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.
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\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.
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\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.
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\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.
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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.
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\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.
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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.
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\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.
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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.
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\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
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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\
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\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.
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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.
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\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.
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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\
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\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.
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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.
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\144\ The HQ is the ratio of observed or modeled exposures to
the RfD.
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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.
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\145\ See the National Scale Mercury Risk Assessment Technical
Support Document.
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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.
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\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).
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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.
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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.
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\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).
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\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\
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\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.
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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.
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\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\
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\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.
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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.
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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.
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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.
---------------------------------------------------------------------------
\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.
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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.
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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
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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-
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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