This is a text-only version of the document "Proposed Air Pollution Standards for Electric Utility Steam Units, EPA, 2011". To see the original version of the document click here.

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Page 1 of 946 The EPA Administrator, Lisa P. Jackson, signed the following notice on 03/16/2011, and EPA is submitting it for publication in the Federal Register (FR). While we have taken steps to ensure the accuracy of this Internet version of the rule, it is not the official version of the rule for purposes of compliance. Please refer to the official version in a forthcoming FR publication, which will appear on the Government Printing Office's FDSys website (http://fdsys.gpo.gov/fdsys/search/home.action) and on Regulations.gov (http://www.regulations.gov) in Docket Nos. EPA-HQ-OAR-2009-0234; EPA-HQOAR-2011-0044. Once the official version of this document is published in the FR, this version will be removed from the Internet and replaced with a link to the official version.

6560-50-P

ENVIRONMENTAL PROTECTION AGENCY 40 CFR Parts 60 and 63 [EPA-HQ-OAR-2009-0234; EPA-HQ-OAR-2011-0044, FRL-9148-5] 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: ACTION: SUMMARY: Environmental Protection Agency. Proposed rule. The United States (U.S.) Environmental Protection

Agency (EPA or Agency) is proposing national emission standards for hazardous air pollutants (NESHAP) from coaland 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).
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On December 20, 2000, EPA determined pursuant to CAA section 112(n)(1)(A) that it was appropriate and necessary to regulate coal- and oil-fired EGUs under CAA section 112 and added such units to the CAA section 112(c) list of sources that must be regulated under CAA section 112(d). (December 2000 Finding; 65 FR 79,825.) On March 29, 2005,

EPA issued a final rule, in which it found that it was neither appropriate nor necessary to regulate coal- and oil-fired EGUs under section 112, and it removed such units from the CAA section 112(c) list of sources (“2005 Action”). 70 FR 15,994. On February 9, 2008, the United

States Court of Appeals for the District of Columbia Circuit (D.C. Circuit Court) vacated the 2005 Action because the Agency violated the CAA by removing EGUs from the CAA section 112(c) list of sources without complying with the delisting requirements in CAA section 112(c)(9). State of New Jersey v. EPA, 517 F.3d 574, 583 (D.C. Cir. 2008), cert. denied, 129 S. Ct. 1308, cert. dismissed, 129 S. Ct. 1313 (2009). (“New Jersey”). EGUs remain a CAA

section 112(c) listed source category. In response to the D.C. Circuit Court’s vacatur, we are proposing CAA section 112(d) NESHAP for all coal- and oil-fired EGUs that reflect the application of the maximum
This document is a prepublication version, signed by EPA Administrator, Lisa P. Jackson on 03/16/2011. We have taken steps to ensure the accuracy of this version, but it is not the official version.

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achievable control technology (MACT), consistent with the requirements of CAA sections 112(d)(2) and (3). This

proposed rule would protect air quality and promote public health by reducing emissions of the hazardous air pollutants (HAP) listed in CAA section 112(b). On February 27, 2006, EPA promulgated amendments to the NSPS for particulate matter (PM), sulfur dioxide (SO2), and nitrogen oxides (NOX) contained in the standards of performance for EGUs (40 CFR part 60, subpart Da, 71 FR 9,866). EPA was subsequently sued by multiple states and State of

environmental organizations on the amendments. New York v. EPA, No. 06-1148(D.C. Cir.).

On September 4,

2009, EPA was granted a voluntary remand without vacatur of the 2006 amendments. These proposed amendments to the NSPS We also are

are in response to the voluntary remand.

proposing several minor amendments, technical clarifications, and corrections to existing NSPS provisions for fossil fuel-fired EGUs and large and small industrialcommercial-institutional steam generating units, 40 CFR part 60, subparts D, Db, and Dc. DATES: Comments must be received on or before [INSERT

DATE 60 DAYS AFTER PUBLICATION IN THE FEDERAL REGISTER]. Under the Paperwork Reduction Act (PRA), comments on the
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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 [INSERT DATE 30 DAYS AFTER PUBLICATION IN THE FEDERAL REGISTER]. PUBLIC HEARING: on this proposal. EPA will hold three public hearings

The dates, times, and locations of the Oral The

public hearings will be announced separately.

testimony will be limited to 5 minutes per commenter.

EPA encourages commenters to provide written versions of their oral testimonies either electronically or in paper copy. Verbatim transcripts and written statements will be If you would like to

included in the rulemaking docket.

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: garrett.pamela@epa.gov. 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 website for this rulemaking, http://www.epa.gov/ttn/atw/utility/utilitypg.html. public hearings will provide interested parties the
This document is a prepublication version, signed by EPA Administrator, Lisa P. Jackson on 03/16/2011. We have taken steps to ensure the accuracy of this version, but it is not the official version.

The

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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 a-and-r-docket@epa.gov, Attention EPA-HQ-OAR-2011-0044 (NSPS action) or EPA-HQ-OAR2009-0234 (NESHAP action). • Fax: Fax your comments to: (202) 566-9744,

Docket ID No. EPA-HQ-OAR-2011-0044 (NSPS action)
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or Docket ID No. EPA-HQ-OAR-2009-0234 (NESHAP action). • Mail: to: Send your comments on the NESHAP action

EPA Docket Center (EPA/DC), Environmental 2822T, 1200 20460,

Protection Agency, Mailcode:

Pennsylvania Ave., NW, Washington, DC Docket ID No. EPA-HQ-OAR-2009-0234. comments on the NSPS action to:

Send your

EPA Docket

Center (EPA/DC), Environmental Protection Agency, Mailcode: 2822T, 1200 Pennsylvania Ave., NW, 20460, Docket ID. EPA-HQ-OAR-

Washington, DC 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., 20503. Deliver your comments

NW, Washington, DC •

Hand Delivery or Courier: to:

EPA Docket Center, EPA West, Room 3334, 1301 20460.

Constitution Ave., NW, Washington, DC

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
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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
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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 Although listed in the

http://www.regulations.gov index.

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 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
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Quality Planning and Standards, U.S. Environmental Protection Agency, Research Triangle Park, North Carolina 27711; Telephone number: 541-5450; E-mail address: NSPS action: (919) 541-5430; Fax number (919) maxwell.bill@epa.gov. For the

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: fellner.christian@epa.gov. 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 and Regulatory Background B. Studies Related to HAP Emissions from EGUs C. EPA’s December 2000 Appropriate and Necessary Finding D. The 2005 Action E. Litigation History 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
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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. Analyses Supporting the 2000 Appropriate and Necessary Finding were Scientifically and Legally Valid, and are Further Reinforced by More Recent Technical Analyses 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 units? 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-floors 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
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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 Resource Group’s Petition for Reconsideration VII. Summary of the Significant Proposed NSPS Amendments A. What are the proposed amended emissions standards forEGUs? 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
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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 LowIncome Populations I. A. General Information 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

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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 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 79,827. 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). In addition to Hg, EGUs are significant emitters of HAP metals such as arsenic (As), nickel (Ni), cadmium (Cd),
1

US EPA. 1997. Mercury Study Report to Congress. 452/R-97-003 December 1997.

EPA-

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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
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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 cobenefits. 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
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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. D.C. 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 The

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 exceeds the level that is adequate to protects public health with an ample margin of safety and that no adverse environmental
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effects will result from the emissions of any source. 112(c)(9)(B).

CAA

The D.C. 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
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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).

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
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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companies.

We further believe that these reductions can be

achieved without significantly affecting the availability and cost of electricity to 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
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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. 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 oilfired EGUs. In addition, as a result of the HAP reductions Thus,

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
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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 3% Discount Rate Total Monetized Benefitsb Hg-related Benefitsc CO2-related Benefits PM2.5-related Cobenefitsd Total Social Costse Net Benefits $59,0 00 $4.1 to $140,00 0 to $5.9 7% Discount Rate $53,00 to $130,0 0 00 $0.45 to $0.89 570

$570

$59,000 to $53,000 to $140,000 $130,000 $10,900 $10,900 $48,0 to $130,00 $42,00 to $130,00 0 0 00 0 Non-monetized Visibility in Class I areas Benefits 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
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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 he 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 F 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 NAICS code1 221112 2211222 Examples of potentially regulated entities Fossil fuel-fired electric utility steam generating units. Fossil fuel-fired electric utility steam generating units owned by the Federal government. Fossil fuel-fired electric utility steam generating units owned by

Category Industry Federal government State/local/ tribal

2211222

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government

municipalities. Fossil fuel-fired electric utility steam generating units in Indian country. 1 North American Industry Classification System. 2 Federal, state, or local government-owned and operated establishments are classified according to the activity in which they are engaged. This table is not intended to be exhaustive, but rather provides a guide for readers regarding entities likely to be affected by this action. To determine whether

921150

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
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Park, North Carolina 27711, Attention:

Docket ID EPA-HQ-

OAR-2011-0044 (NSPS action) or Docket ID EPA-HQ-OAR-20090234 (NESHAP action). Clearly mark the part or all of the For CBI information

information that you claim to be CBI.

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
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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: garrett.pamela@epa.gov.

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 website 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
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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 Controls for fuels and vehicles are

also been addressed.

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.
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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
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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. 1. Statutory and Regulatory Background 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 health. Legislative History of the CAA Amendments of 1990
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(“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 riskThis document is a prepublication version, signed by EPA Administrator, Lisa P. Jackson on 03/16/2011. We have taken steps to ensure the accuracy of this version, but it is not the official version.

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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 source3 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
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 31,576, 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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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).

Congress established a specific structure for determining whether to regulate EGUs under section 112.5 Specifically, Congress enacted CAA section 112(n)(1). 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
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). 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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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.”). Once a source category is listed pursuant to section 112(c), the next step is for EPA to establish technologybased 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 The

achievable control technology” or “MACT” standards.

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. 112(d)(3)(A) and (B). See CAA section

This level of minimum stringency is

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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. section 112(d)(3). See CAA

EPA also must consider more stringent When considering

“beyond-the-floor” control options.

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 healthbased 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.” 7412(d)(4). 42 U.S.C. §

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
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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. November 15, 1993. This report was required by

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.” 112(n)(1)(B). See CAA section

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.” both of these reports by 1998. 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 Id. EPA completed

section 112(n)(1)(C) directed NIEHS to conduct “a study to
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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. 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). NIEHS submitted this Report to Congress in August,

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.
7

65

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.
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FR 79,826.

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. Conf. Rep. No 105-769, at 281-282 (1998). The NAS Study evaluated the same issues as those required to be considered under section 112(n)(1)(C). The See H.R.

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. 2. 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.
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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 D.C. Circuit Court. a. i. Studies Related to HAP Emissions from EGUs The Utility Study EPA issued the Utility Study in February 1998, over 4 years after the statutory deadline. included numerous analyses. The Utility Study

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.
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EPA determined that 67 HAP were emitted from EGUs.

In

addition, the study evaluated HAP emissions based on two scenarios: emissions. 1) 1990 base year; and 2) 2010 projected 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 coalfired EGUs and Ni emissions from oil-fired EGUs contributed
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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. 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. not assessed. In estimating future emissions from EGUs, EPA
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For

Multipathway risks for 2010 were

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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. TABLE 2. HAP Arsenic Chromium Mercury Nickel NATIONWIDE EMISSIONS FOR SIX PRIORITY HAP, tpy Coal 1990 61 73 46 58 2010 71 87 60 69 1990 5 4.7 0.25 390 2,900 140 Oil 2010 3 2.4 0.13 200 1,500 73 Natural gas 1990 0.15 0.0015 2.2 NM NM 2010 0.25 0.024 3.5 NM NM

Hydrogen chloride 143,00 155,00 0 0 Hydrogen fluoride 20,000 26,000

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 EPA also concluded

least some of all the trace metals.

that PM controls tend to effectively remove the trace
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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. ii. 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
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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.
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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 re-emissions from the global pool). The Mercury Study noted that those who regularly and frequently consume large amounts of fish – either marine
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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. Mercury Study also evaluated Hg emissions control technologies and the costs of such technologies. iii. 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, The

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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 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
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concerned citizens.

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 (µg/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. weight of evidence for carcinogenicity of MeHg was inconclusive. There was also evidence from animal studies The

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
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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. b. 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
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section 114 of the CAA.

65 FR 79,826-27.

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 79,826. EPA also solicited

data from the public through a February 29, 2000, notice (65 FR 10,783). 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 79,826.

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 In evaluating Hg

of greatest concern in the Utility Study.

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 65

corroborated the Hg emissions estimates in the study. FR 79,828.

In the finding, EPA explained that Hg is highly

toxic and persistent and that it bioaccumulates in the food
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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 79,827. 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 79,827.

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 79,827.

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 79,827. 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 79,827.

In discussing the non-Hg HAP from coal- and oil-fired EGUs, EPA stated that HAP metals such as As, Cr, Ni, and Cd
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are of potential concern for carcinogenic effects. 79,827. EPA acknowledged that the risk assessments

65 FR

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 79,827. EPA further stated that dioxins, HCl, and HF

were of potential concern and could be evaluated further during the regulatory development process. 65 FR 79,827.

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 79,827.

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 79,828. EPA then made nine specific conclusions based on the information in the record, some of which are summarized
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above.

65 FR 79,829-30.

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 79,830. 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 FR 79,830. EPA explained that it was

appropriate to regulate HAP emissions from coal- and oilfired units because it had identified certain control options that, it anticipated, would effectively reduce HAP from such units. 65 FR 79,830. 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 79,830.

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
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identified in the Utility RTC and confirmed by the NAS Study, and which section 112 is intended to address.” FR 79,830. 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 79,831. 65

In light of the positive appropriate and necessary determination, EPA in December 2000 listed coal- and oilfired EGUs on the section 112(c) source category list. FR 79,831. c. The 2005 Action On March 29, 2005, EPA issued the Section 112(n) Revision Rule (“2005 Action”) that has since been vacated by the D.C. Circuit Court. In that rule, EPA reversed the 65

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 15,994. 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 oilThis document is a prepublication version, signed by EPA Administrator, Lisa P. Jackson on 03/16/2011. We have taken steps to ensure the accuracy of this version, but it is not the official version.

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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 15,998. 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
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emissions from other sources.

70 FR 15,998.

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 15,600. 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 16,001. 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
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the finding was overbroad to the extent that it relied on environmental effects. 70 FR 16,002. 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 16,003-4.

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 (D.C. Cir. 2008).
8

On May 18, 2005, EPA issued the Clean Air Mercury Rule (CAMR). 70 FR 28,606. 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 16,004. 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 16,005.

EPA also determined that it was not appropriate and necessary to regulate coal-fired EGUs on the basis of nonHg HAP emission or oil-fired EGUs on the basis of Ni and non-Ni HAP. d. 70 FR 16,007.

Litigation History Shortly after issuance of the December 2000 Finding,

an industry group challenged that finding in the D.C. Circuit Court. UARG v. EPA, 2001 WL 936363, No. 01-1074 The D.C. Circuit Court

(D.C. Cir. July 26, 2001).

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
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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 from the section 112(c) source category list without following the requirements of section 112(c)(9). On February 8, 2008, the D.C. Circuit Court vacated both the 2005 Action and CAMR. The D.C. Circuit Court held

that EPA failed to comply with the requirements of section 112(c)(9) for delisting source categories. Specifically,

the D.C. 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 D.C. 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 D.C. Circuit Court found that EPA’s contrary

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position would “nullify §112(c)(9) altogether.” Jersey, 517 F.3d at 583.

New

The D.C. 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 D.C. 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 D.C. 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. On December 18, 2008, several environmental and public health organizations (“Plaintiffs”)10 filed a complaint in
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. 10 American Nurses Association, Chesapeake Bay Foundation, Inc., Conservation Law Foundation, Environment America, Environmental Defense Fund, Izaak Walton League of America,
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the D.C. 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 statutorilymandated deadline, December 20, 2002, 2 years after such sources were listed under section 112(c). litigation. EPA settled that

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 coaland oil-fired EGUs by March 16, 2011, and a notice of final rulemaking by November 16, 2011. 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 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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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 issued. 2000 Finding was

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).
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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].” added). (emphasis

Congress did not define the phrase “appropriate Rather, Congress

and necessary” in section 112(n)(1)(A).

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 (D.C. 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
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Association, et al. v. FCC, 330 F.3d 502, 510 (D.C. 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 (D.C. 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.” Jersey, 517 F.3d at 578 (citations omitted). New

We describe Also,

above the two-phased approach to standard setting.

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relevant, however, is that Congress set very strict deadlines for listing source categories and issuing emission standards for such 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 In addition to directing EPA to regulate EGUs

from 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
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Study) pursuant to section 112(n)(1)(C).11 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
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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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. 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 Section

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
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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
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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
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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

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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 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
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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
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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
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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
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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
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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
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health or the environment associated with HAP emissions from EGUs unless 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. For these

EPA, 233 F.3d 625, 633 (D.C. Cir. 2000).

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
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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

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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 79,827. 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 Further, the

making the appropriate determination.

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 iii.
12

The 2005 Action

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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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 The Agency should

of the provisions of section 112(n)(1).

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
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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.
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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

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think it 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 D.C. 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.” 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 Cellular Telecommunication, 330 F.3d at

we must find it necessary based on such a finding even if
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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. 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
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Necessary after Imposition of the Requirements of the

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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].” 112(n)(1)(A). Congress did not define the phrase “after imposition of the requirements of the Act.” The plain meaning of the Section

term “requirement” is something that is necessary, or obligatory. See, e.g., Random House Webster’s Unabridged Given that Congress

Dictionary, Deluxe Edition, 2001.

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
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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 steamelectric 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,
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including Hg emissions.

The ARP also included requirements Considering the Acid

for limiting NOX emissions from EGUs.

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. 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 The Agency issued

impose these provisions directly on EGUs, however.
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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 ESStates use a broad

25, 1-3, 2-32, 3-14, and 6-15.

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
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in determining whether it is necessary to 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
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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 stateinitiated and citizen-initiated enforcement actions.13
13

We

In our analysis, we included state requirements and
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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 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

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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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 bioaccumulative 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
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section 112 necessary. 497, 525 (2007).

See Massachusetts v. EPA, 549 U.S.

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 Rule15). If such rules are either not finalized or upheld

by the Courts, the level of risk would potentially increase. We also may find it necessary to regulate EGUs under
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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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 cobenefit 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 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

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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 Because

authority to address hazards from HAP emissions.

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,

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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. reasonable. Congress enacted section 112 for the express purpose
16

This interpretation is not

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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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. 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
17

In theory, an NSPS is legally permissible for new stationary sources of HAP.
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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
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EPA to use in determining whether HAP emissions from EGUs pose a hazard to public health. defined elsewhere in the CAA. The phrase is also not

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
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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 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
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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
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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.” 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 36,440 (July 7, Further, the section 67

1997); 63 FR 14,094 (March 24, 1998).

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. 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 Id.

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not exclude impacts that might occur in only one region of the country. d. Id.

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
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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 D.C. Circuit Court has already held that section 112(n)(1) “governs how the Administrator decides whether to list EGUs” and that once listed, EGUs are subject to the requirements of section 112. Jersey, 517 F.3d at 583. New

Indeed, the D.C. Circuit Court

expressly noted that “where Congress wished to exempt EGUs from specific requirements of section 112, it said so
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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).
18

EPA

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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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. 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 79,826-27. The Utility, Mercury, and NAS

Studies together consisted of thousands of pages of information and technical analyses. All of these studies In fact, the Mercury The

were peer reviewed prior to issuance.

Study was reviewed by over 65 independent scientists.19 NAS Study contains a thorough technical discussion

summarizing the state of the science at the time regarding the human health effects of MeHg. In addition to conducting the studies that Congress required, EPA collected relevant information on Hg emissions and available control technologies.
19

Mercury Study Report to Congress, Vol. I, Pg. 6, December 1997.
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Specifically, pursuant to a CAA section 114 ICR, EPA collected data on the Hg content in coal from all coalfired 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 79,826. 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 79,826 (citing 65 FR 18,992).

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 65 FR

evaluation with other parties, including the DOE. 79,826. EPA also evaluated other emission control

approaches that would reduce EGU HAP emissions. 79,827-29.

Id. at

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
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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. Conf. Rep. No 105-769, at 281-282 (1998).20 After considering all of the information that Congress
20

See H.R.

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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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
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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 nonHg 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.
21

http://yosemite.epa.gov/sab/SABPRODUCT.nsf/FF2962529C7B158A 852571AE00648B72/$File/ehc9801.pdf
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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. 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.” response to the SAB review, the Agency conducted additional, comprehensive analyses addressing SAB’s recommendations. Thus, in 2000, the Agency had before it a In direct

comprehensive record concerning Hg emissions, including the best available science on Hg at the time. 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 79,827. The Agency explained

that “mercury is highly toxic, persistent, and bioaccumulates in food chains;” that Hg deposited on land
22

The central conclusions underlying the 2000 finding are described in detail in the 2000 notice, at 65 FR 79,829-30.
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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. 79,827. 65 FR

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, with 13 of those states issuing advisories for all the water bodies in their state. 79,827. 65 FR

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 79,830. EPA

agreed with 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 79,830.

The Agency then identified the most affected populations. Specifically, the Agency concluded that women

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of childbearing age are the population of greatest concern because the developing fetus is the most sensitive to the effects of MeHg. 65 FR 79,827. 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. 79,827. 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 79,827. The Agency acknowledged 65 FR

that there was uncertainty with risk at exposure above the RfD, but indicated that risk increased with increased exposure. 65 FR 79,827. 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 79,830.

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
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percentage of fish sampled in lake surveys.

65 FR 79,830.

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. 79,830. 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 79,827. 65 FR

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 79,827. EPA identified

coal combustion and waste incineration as the source categories likely to bear the greatest responsibility for
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direct anthropogenic Hg deposition in the continental U.S. 65 FR 79,827. 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. 79,827. 65 FR

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 In 2000, the Agency also found a plausible link between domestic anthropogenic Hg emissions and MeHg in fish. 65 FR 79,829. 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 79,830. Those facts included, for example,

the link between coal consumption and Hg emissions, EGUs being the largest domestic source of Hg, and certain
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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segments of the population being at risk for adverse health effects due to consumption of contaminated fish. 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 Id.

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. 2-3. At the time of the December 2000 Finding, the Agency
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See Mercury Study, Volume 3, page

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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 5,507 (February 11, 1991), as amended, and 40 CFR part 60, subpart Eb (Emissions Guidelines), 60 FR 65,419 (December 19, 1995), as amended; Standards for Medical Waste Incinerators, 40 CFR part 60, subpart Ec (NSPS), 62 FR 48,382 (September 15, 1997), as amended, and 40 CFR part 60, subpart Ce (Emission Guidelines), 62 FR 48,379 (September 15, 1997); Standards for Hazardous Waste Combustors, 40 CFR part 63, subpart EEE, 64 FR 53,038 (September 30, 1999); Standards for Small Municipal Waste Combustors, 40 CFR part 60, subpart AAAA (NSPS), 65 FR 76,355 (December 6 2000), and 40 CFR part 60, subpart BBBB (Emissions Guidelines), 65 FR 76,384 (December 6, 2000); and standard for Portland cement manufacturers (40 CFR part 63, subpart LLL, 64 FR 31,925 (June 14, 1999)).24
24

Most of these categories emitted far less Hg than

The NESHAP for Portland cement did not include a standard for Hg when initially promulgated. In National Lime Ass’n v. EPA, the D.C. 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,
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EGUs at the time of the finding.

Thus, at the time EPA

made the December 2000 Finding, the record 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. 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 79,830.

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 longterm goal of reducing the mobilization of Hg to the 634 (D.C. 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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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 79,827.

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
25

Moreover, EPA did not have

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
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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. 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 79,827.

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 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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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 79,830. 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.
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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 79,827. 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 79,827; 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 79,827.

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
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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 lifetime cancer risk greater than one in one million to
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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. 79,828-30. 65 FR

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
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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 79,830. 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 79,828. 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.
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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 coalfired EGUs would increase by 2010. 65 FR 79,828 (Table 1).

For Hg, EPA estimated that EGUs emitted 46 tons of Hg in 1990, 43 tons of Hg in 1999, and it projected that EGUs would emit approximately 60 tons of Hg in 2010. 79,827-828. 65 FR

EPA also estimated an overall increase in nonGiven these

Hg HAP emissions from coal-fired EGUs.

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
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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. a. 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 As

below, we reject these assertions as unfounded.

demonstrated above, EPA’s 2000 appropriate and necessary finding was sound and fully supported by the record before
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the Agency in 2000. i. 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,

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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. ii. 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 both the appropriate and necessary prongs. As explained in Section III.A, this interpretation
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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

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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.
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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. for the ARP in its 2010 projections. EPA accounted

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

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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 EPA could

developing regulations to meet the NOX SIP call. 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
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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 D.C. 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
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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.” 112(c)(9)(B)(ii). Here, we have a validly listed source category. EPA Section

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 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
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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. analyses that we conducted. We discuss below the new

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. analyses. Utilities are by far the largest remaining source of Hg in the U.S.26 In addition, EGUs are the largest source of We solicit comment on the new

HCl, HF, and Se emissions, and a major source of metallic HAP emissions including As, Cr, Ni, and others.27 The
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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discrepancy is even greater now that almost all other major source categories have been required to control Hg and other HAP under section 112. 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
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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. Finally, we find that it remains appropriate to regulate EGUs under section 112 because we have identified a
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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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
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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
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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 nonHg 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: gaseous

elemental Hg (Hg0), 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

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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
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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 Zealand34 added substantially to the body of knowledge on
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, AlTikriti 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 form 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., Sørensen, N., Dahl, D., Yokoyama, K., Jørgensen, 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.
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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. 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 In

deficits as measured in several different tests among these studies be used as the basis for the RfD. 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

Solna, Sweden: National Swedish Environmental Protection Board. Report No.: Report 3642.
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the integrative analysis of all three studies.”35 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 µg/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
35

EPA, 2001
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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 However,

the new literature has not been completed by EPA.

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.
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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 supported the use of results from neurobehavioral or neuropsychological tests. The NAS

report37 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. following: They concluded the

“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 37

NAS, 2000 NAS, 2000
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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.
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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 Tapajós River region in Brazil38 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. v. Immunotoxic Effects Although exposure to some forms of Hg can result in a

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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decrease in immune activity or an autoimmune response,39 evidence for immunotoxic effects of MeHg is limited.40 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 cancer43). There is also some evidence of reproductive and renal toxicity in humans from MeHg exposure. However, overall,

human data regarding reproductive, renal, and hematological
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. 41 IARC, 1994 42 EPA, 2002 43 NAS, 2000
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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. in the world. There is a fixed amount of it

As long as it is bound up, for example in Once it

coal, it cannot affect people or the environment.

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 (Hg0, 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
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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. 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 reAnthropogenic Hg emissions consist of Hg0, Hg+2,

emitted Hg originates from anthropogenic sources.47,48 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), 454466. 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., Jaeglé, L., et al. (2007). Chemical cycling and deposition of atmospheric mercury: Global
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Current estimates of total global Hg emissions based on a 2005 inventory 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 5,790 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

constraints from observations. J. Geophys. Res, 112, 10711077. 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
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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 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 In 2005,

units above 25 MW were 43 out of 115 tons.57

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 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. 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.
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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 Table 3 also

emissions from other major non-EGU Hg sources.

shows EPA’s projection that U.S. EGU emissions will continue
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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 TABLE 3. ANTHROPOGENIC HG EMISSIONS AND PROJECTIONS IN THE U.S.* 2005 Mercury (tons) 53 7.5 7.0 6.4 3.3 3.2 3.1 2.5 2.3 17 2016 Mercury (tons) 29 1.1 4.6 4.6 3.3 2.1 0.3 0.7 2.3 16

Category Electric Generating Units Portland Cement Manufacturing Stainless and Nonstainless Steel Manufacturing: Electric Arc Furnaces Industrial, Commercial, Institutional Boilers & Process Heaters Chemical Manufacturing Hazardous Waste Incineration Mercury Cell Chlor-Alkali Plants Gold Mining Municipal Waste Combustors Sum of other source categories (each of which emits less than 2 tons)

Total 105 64 * Emissions estimates are presented at a maximum of two significant figures.

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.
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c.

Atmospheric Processing and Deposition of Hg Mercury is known to exist in the atmosphere in three

forms:

Hg0, Hg+2, and HgP.

The dominant form of Hg in the

atmosphere is Hg0.59

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 soluble) and HgP are

more readily scavenged by precipitation and have higher dry deposition velocities than Hg0 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 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 drydeposition of speciated mercury to the Florida Everglades: Measurements and modeling.” Atmospheric Environment 41(1): 136-149.
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species, relative to emissions of Hg0.

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 Hg0. Control of emissions of Hg0

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. 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
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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
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.
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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 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,
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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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 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
65

EPA states in its IRIS database that data

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  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. 67 U.S. Environmental Protection Agency (U.S. EPA). 2000.
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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 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 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. 72 Aksoy, M. (1989). Hematotoxicity and carcinogenicity of benzene. Environ. Health Perspect. 82: 193-197. 73 Goldstein, B.D. (1988). Benzene toxicity.
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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 IARC has determined that Cd is

are known human carcinogens. carcinogenic to humans.

EPA has determined that Cd is a

probable human carcinogen.74 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 Occupational medicine. State of the Art Reviews. 3: 541554. 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 . 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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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 bloodstain sputum). Intoxication with high concentrations of Cl2 Exposure to Cl2 can lead to

may induce lung collapse.

reactive airways dysfunction syndrome (RADS), a chemical irritant-induced type of asthma. Dermal exposure to Cl2 may EPA has

cause irritation, burns, inflammation and blisters. not classified Cl2 with respect to carcinogenicity. 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
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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 Trivalent Cr is less toxic than Cr+6. The

carcinogen.

respiratory tract is also the major target organ for Cr+3 toxicity, similar to Cr+6. 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 After EPA has not classified Cr+3 with

reviewing recently published epidemiological data.

reviewing the currently available epidemiological evidence, the IARC (2006) characterized the human evidence for formaldehyde carcinogenicity as “sufficient,” based upon the
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.
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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. 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. are several studies that suggest that formaldehyde may increase the risk of asthma – particularly in the young.78,79
77

There

International Agency for Research on Cancer (2006) Formaldehyde, 2-Butoxyethanol and 1-tert-Butoxypropan-2-ol. Monographs Volume 88. World Health Organization, Lyon, France. 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
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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
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. 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#bookmar k02.
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failure to evacuate an area promptly when exposed.

Hydrogen

chloride has not been classified for carcinogenic effects.81 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 One study

levels of fluoride may cause dental fluorosis.

reported menstrual irregularities in women occupationally exposed to fluoride via inhalation. classified HF for carcinogenicity82. x. Lead The main target for Pb toxicity is the nervous system, both in adults and children. Long-term exposure of adults The EPA has not

to Pb at work has resulted in decreased performance in some
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. 82 U.S. Environmental Protection Agency. Health Issue Assessment: Summary Review of Health Effects Associated with Hydrogen Fluoride and Related Compounds. EPA/600/889/002F. Environmental Criteria and Assessment Office, Office of Health and Environmental Assessment, Office of Research and Development, Cincinnati, OH. 1989.
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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. determined. No safe blood Pb level in children has been At lower levels of exposure, Pb can affect a Fetuses exposed to Pb

child’s mental and physical growth.

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 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
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 .
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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 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
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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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 carcinogen85,86. The IARC has classified Ni

compounds as carcinogenic to humans.87 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 EPA has classified

carcinogenic in animals exposed orally.

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.
85

Acid gas and

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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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 These

emissions from EGUs include HCl, HF, Cl2, and HCN.

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, 110,000 tons for HCl, and 36,000 tons for HF.88 TABLE 4. SUMMARY OF ACID GAS EMISSIONS FROM EGU SOURCES 2005 Acid HAP Emissions from the National Air Toxics Assessment (NATA) U.S. EGU Emissions Hyd rog en Cya
88

Percent of total U.S. anthropogenic emissions in 2005 Non EGU emission s 14,000 8%

1,200

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.
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nid e3 Hydrogen 350,00 78,000 Chloride 0 Hydrogen 47,000 28,000 Fluoride 1 Using cyanide emissions for HCN. ii. Metal HAP

82% 62%

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 7 and 68 percent of national metal HAP emissions, and as a result it remains appropriate to regulate EGUs. TABLE 5. SUMMARY OF METAL EMISSIONS FROM EGU SOURCES 2005 Metal HAP Emissions from the inventory
89

Percent of total U.S. anthropogenic emissions in 2005

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.
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used for the National Air Toxics Assessment (NATA) U.S. EGU Emissions Antimony Arsenic Beryllium Cadmium Chromium Cobalt Manganese Nickel Selenium 3. 19 200 10 25 120 54 270 320 580 Non EGU emi ssi ons 83 120 13 38 430 60 180 0 840 120

19% 62% 44% 39% 22% 47% 13% 28% 83%

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

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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 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
90

U.S. EPA. 2011. Technical Support Document: NationalScale 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: NonMercury 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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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

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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. 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 The 2010 ICR shows the EGU Hg and HCl totals

are lower than in 2005, at 29 tons and 106,000 tons respectively. 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
93 94

Strum, M., Houyoux, M., op. cit., Section 4. 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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Hg risk analysis described below, as the projected emissions are almost the same as current HAP emissions from EGUs. c. i. National-Scale Hg Risk Modeling 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

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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. 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 In

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 selfcaught 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
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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. 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 Our

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
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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 oceangoing 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

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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
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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 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

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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. 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 The fish tissue dataset for the risk assessment
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. 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.
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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. from three sources: The fish tissue samples come primarily 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 This

fish tissue MeHg data had multiple measurements.

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
97

http://water.epa.gov/scitech/swguidance/fishshellfish/fisha dvisories/
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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). Deposition of Hg for the continental U.S. was estimated using the Community Multiscale Air Quality model v4.7.1 (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. EGUThis document is a prepublication version, signed by EPA Administrator, Lisa P. Jackson on 03/16/2011. We have taken steps to ensure the accuracy of this version, but it is not the official version.

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attributable Hg deposition is based on the distribution of U.S. EGU-attributable deposition. occur at the same watershed. TABLE 6. COMPARISON OF TOTAL AND U.S. EGU-ATTRIBUTABLE HG DEPOSITION (µg/m2) FOR THE 2005 AND 2016 SCENARIOS.* 2005 U.S. EGUTotal Hg attributab Deposition le Hg Deposition 19.41 0.89 17.25 0.24 2016 ** U.S. EGUTotal Hg attributab Deposition le Hg Deposition 18.66 0.34 16.59 0.15 These percentiles do not

Statistic

Mean Median 75th 23.69 1.07 22.83 0.46 percentile 90th 30.78 2.38 29.90 0.85 percentile 95th 36.85 3.60 35.16 1.18 percentile 99th 58.32 7.77 56.23 2.41 percentile * 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. Table 6 and 7

cannot be directly compared, as the watershed with the 99th percentile U.S. EGU-attributable deposition is not the same
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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. TABLE 7. COMPARISON OF PERCENT OF TOTAL HG DEPOSITION ATTRIBUTABLE TO U.S. EGUS FOR 2005 AND 2016.*

Statistic 2005 2016 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 EGUattributable 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
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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
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 nonair 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).
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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 Tables 8 and 9 of this preamble. Table 8 of this preamble compares

total and U.S. EGU-attributable fish tissue Meg concentrations for the 2005 and 2016 scenarios by watershed percentile. 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 U.S. EGUU.S. EGUTotal Total attributable attributable 0.31 0.024 0.29 0.008 0.23 0.014 0.20 0.005 0.39 0.032 0.36 0.011 0.67 0.056 0.63 0.019 0.91 0.079 0.87 0.026 1.34 0.150 1.29 0.047

Statistic Mean Percentile Percentile Percentile Percentile Percentile

50th 75th 90th 95th 99th

Because the focus of this analysis is on higherconsumption self-caught fisher populations active at inland freshwater locations, we identified surveys of higher
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consumption fishing populations active at inland freshwater rivers and lakes within the continental U.S. to inform the selection of consumption rate scenarios.100 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. 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 A number of criteria had to be met for a study to be used in providing explicit consumption rates for the highend 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.
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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 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
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). 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.
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concentrations) was also included in exposure calculations.103 Our estimates of total percent of watersheds where female subsistence fishing populations may be at risk from exposure to 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
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.
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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). Of the total number

of watersheds where populations may be at risk from exposures to 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 exposure104 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. The two estimates of percent of watersheds where populations may be at risk from EGU-attributable Hg do not
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.
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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.
105 105,106,107,108

However, EPA does not have sufficiently

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
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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. EGUattributable risk). 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 and local knowledge to confront asthma and subsistencefishing hazards in Greenpoint/Williamsburg, Brooklyn, New York. Environmental Health Perspectives, 110(2) 109 Specifically, upper percentile risk estimates for the high-end female consumer assessed at the national level
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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 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., 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 the 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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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 underrepresentation 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 levels111.
111

These sensitivity

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 sources 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
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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. We also examined the potential for underrepresentation 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. 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.
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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. EGUattributable 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. EGUattributable MeHg could be substantially larger than the number estimated based on the available fish tissue MeHg sampling data. e. 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 The

assessment was performed for each case study facility.

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).
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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
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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,

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we 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-organspecific 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 doseresponse 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).
113

In this assessment, we used

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-00002. http://www.epa.gov/ncea/raf/pdfs/chem_mix/chem_mix_08_2001. pdf.
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the IRIS RfC values for Cr+6 and HCl, the ATSDR MRL for Ni compounds, and the California Environmental Protection Agency REL for As. 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 oilfired units). The maximum chronic impacts of HCl emissions Because

were all less than 10 percent of its chronic RfC.

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
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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. f. 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
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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
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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 fish115 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. affects avian species.
115

Mercury also

In previous reports116 much of the

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,
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focus has been on large fish-eating species, in particular the common loon. Breeding loons experience significant

adverse effects including behavioral (reduced nestsitting), physiological (flight feather asymmetry) and reproductive (chicks fledged/territorial pair) effects.117 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 efficiency118 and decreased reproductive success and altered pair behavior.119 These

effects include significantly more unproductive nests, male/male pairing, reduced courtship behavior and lower Research Triangle Park, NC., March; EPA report no. EPA452/R-05-003. Available on the Internet at 0 (672 sites) Top ten percent U.S. EGU in Hg emissions (67 sites) 1.65 (119%) 4.89 (352%) 0.36 (93%) 1.18 (302%)

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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, 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. Hg can be present in one of three forms: The

as Hg0, 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
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control.

The form (or “speciation”) of the Hg is

determined by the flue gas chemistry and by the timetemperature profile in the post combustion environment. During coal combustion, Hg is released into the exhaust gas as Hg0. This vapor may then continue through the flue gas

cleaning equipment and exit the stack as gaseous Hg0 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 It is thought that

surface of fly ash and unburned carbon.

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 Hg0 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

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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 Hg0 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
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device.

The carbon is injected to maximize contact with Mercury binds on the surface of the carbon

the flue gas.

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 TOXECON™ configuration can This configuration

keep the fly ash and the AC separate.

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consists of the primary PM control device (ESP or FF) followed by a secondary downstream pulsejet FF. injected prior to the secondary FF. The AC is

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 An existing

usually provide better performance than ESPs.

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,

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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 This is

may also partition in small amounts to Cl2.

normally a very small fraction relative to the formation of HCl. Limited testing has shown that Cl2 gas is also

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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 41 percent of anthropogenic Hg (excluding fires) in the continental US. Application of available Hg

controls in 2016 that would be required under section 112 reduces 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 54 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 47 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

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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 metals129, results in reductions of approximately 530 tons of metals per year.130 EPA believes these projected reductions in Hg, acid gases, and metal HAP emissions demonstrate the effectiveness of available controls. 7. 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
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 47 percent of 1,400 tons, which is the total tonnage of metals from Table 3.
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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. 8. It Remains Appropriate and Necessary to Regulate EGUs to

Address Public Health and Environmental Hazards Associated
131

Governing Council of the United Nations Environment Programme http://www.unep.org/hazardoussubstances/Mercury/Negotiation s/Mandates/tabid/3321/language/en-US/Default.aspx
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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 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, 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 EGU sources that emit Hg; 5) Hg emissions from EGUs affect not only deposition, exposures, and risk today, but may contribute to future
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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
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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
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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 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
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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
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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. 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 Adverse

insect-eating birds including many songbirds.

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.
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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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 In fact, Hg emitted by EGUs in the

impacts for many years.

past, including over the last decade, is still having impacts on concentrations of Hg in fish today. Failing to

control Hg emissions from 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 US 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

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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. 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 As

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 many 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
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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. c. Effective Controls are Available to Reduce Hg and Non-Hg
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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 Activated

are all effective in removing metal HAP as well.

carbon injection is the most successfully demonstrated Hgspecific 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

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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

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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

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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
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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 The 2005

2005 and 2010 emission estimates are not the same.

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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 The

reductions would have occurred between 2005 and 2010.

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 State Hg

no national, Federally binding regulations for 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). 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
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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
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of coal- and oil-fired EGUs on the list of source categories regulated under CAA section 112(c). 9. 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
133

In addition, children breathe through their

U.S. Environmental Protection Agency. 2006. Revision of the metabolically-derived ventilation rates within the Exposure Factors Handbook. (External review draft)
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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. 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

Washington, DC: Office of Research and Development. EPA/600/R-06/129A. http://oaspub.epa.gov/eims/eimscomm.getfile?p_download_id=4 60261. 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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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. 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

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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systems.138

Exposure at a young age to these carcinogens

could lead to a higher risk of developing cancer later in life. 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 A meta-analysis

affect children’s neurologic development.

of seven studies has shown an association between exposure to formaldehyde, another HAP of concern, and development of asthma in children.141
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_suppleme nt_final.pdf 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
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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 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 Systematic Review. Environ Health Perspect 118: 313–317.

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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. 10. 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 oilfired EGUs under section 112. 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.
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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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 ug/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 Upon further consideration, EPA concludes that it did not have a scientific or technical justification for creating a metric other than the HQ144 to compare U.S. EGUattributable exposures to the RfD.
143

As EPA recognized in

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. 144 The HQ is the ratio of observed or modeled exposures to the RfD.
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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. Ninety-eight percent of watersheds with fish tissue MeHg samples have Hg deposition levels such that total
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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
145

See the National Scale Mercury Risk Assessment Technical Support Document.
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where total exposures to MeHg exceed the RfD. 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). reasons for the finding in 2005: EPA cited three

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. 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, EPA

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.
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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

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

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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
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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
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 subsistencefishing hazards in Greenpoint/Williamsburg, Brooklyn, New York. Environmental Health Perspectives, 110(2).
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likely. 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 [INSERT DATE OF PUBLICATION OF THIS PROPOSED RULE IN THE FEDERAL REGISTER].
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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
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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.
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The Small Entity Representatives (SERs) serving on the Small Business Advocacy Review Panel (SBAR) established under the Small Business Regulatory Enforcement Fairness Act (SBREFA) suggested that EPA consider developing an area-source (i.e., those EGUs emitting less than 10 tpy of any one HAP or less than 25 tpy of any combination of HAP) vs. major-source (i.e., those EGUs emitting 10 tpy or more of any one HAP or 25 tpy of more of any combination of HAP) distinction for this source category. The proposed 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 wellcontrolled 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
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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. explained above, that is not the case here. But, as

Accordingly,

we believe it is appropriate to set MACT standards for both major and area source EGUs. proposed approach. EPA solicits comment on its

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
151

As we have explained in other rules, determining what constitutes GACT involves considering the control technologies and management practices that are generally
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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 D.C. Circuit Court Decisions In March 2007, the D.C. 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 bestperforming 12 percent of existing sources, not levels EPA considers to be achievable by all sources (479 F.3d at 880–81);

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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•

EPA cannot set floors of “no control.”

The D.C.

Circuit Court reiterated its prior holdings, including National Lime Ass’n. v. EPA (233 F.3d625 (D.C. 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 D.C.

Circuit Court held that “EPA’s decision to base floors exclusively on technology even though nontechnology factors affect emissions violates the Act.” (479 F.3d at 883.) The D.C. Circuit Court

also reiterated its position stated in Cement Kiln Recycling Coalition v. EPA, 255 F.3d 855 (D.C. 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
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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. at 640. The Brick MACT decision also stated that EPA may account for variability in setting floors. The D.C. National Lime II; 233 F.3d

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 D.C. Circuit Court opinion is also relevant to this proposal. In Sierra Club v. EPA, 551 F.3d 1019

(D.C. Cir. 2008), the D.C. 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
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practices.”

As a result of the D.C. 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 D.C. 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 D.C. 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 D.C. Circuit Court found that PM is a 1) “HAP metals are

reasonable surrogate for HAP if:

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
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particular numerical reduction in HAP metal emissions.” 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

We

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 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 coaland oil-fired EGUs pursuant to CAA section 112(d). section 114(a) states, in pertinent part: For the purpose of...(iii) carrying out any CAA

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
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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
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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 01, 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 coaland 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. 31,725 (July 2, 2009). 74 FR

We received comments from industry We also met with industry and

and other interested parties.

other interested parties, and published a revised ICR in the Federal Register for another round of comments consistent with the PRA. 74 FR 58,012 (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
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components.

The first component solicited information from EPA provided the survey in

all potentially affected units.

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

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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-HQOAR-2009-0234-0062. In phase one, all coal- and oil-fired EGUs identified by EPA as being potentially subject sources under the
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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.
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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 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
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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 oilfired 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,
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thus, will react easily in an acid-base reaction with caustic sorbents (e.g., lime, limestone). for HF. The same is true

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 Limited testing has shown

relative to the formation of HCl.

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
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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 54,970, September 9, 2010 (final rule); major and area source Industrial, Commercial, and Institutional Boilers and Process Heaters NESHAP (collectively, Boiler NESHAP), 75 FR 32,005, June 4, 2010; 75 FR 31,895, 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 HCN152 to establish individual emission limitations if warranted. 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
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.
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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-tochlorine ratio (S:Cl) in the flue gas is greater than 1.0,

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.
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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.
154

Sampling and analytical methods for dioxins/furans

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.
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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 becomes impractical, if not infeasible, for continuous monitoring. 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-OAR2009-0234-0062. 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 54,970; September 9, 2010); Boiler NESHAP – CO (75 FR
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32,005, June 4, 2010; 75 FR 31,895, June 4, 2010 (proposed rules; the final rules were signed on February 21, 2011)); Hazardous Waste Combustor NESHAP - CO (64 FR 52,828; 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-HQOAR-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.
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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 The 170 units with the newest PM

number with ACI installed.

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)
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of Hg in the flue gas.

Mercury may exist as Hg0, as Hg+2 (or Based on available

reactive gaseous Hg, RGM) or as Hgp.

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 coalfired units not selected in any of the above groups to test; specifics of the required testing may be found in Docket
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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-HQOAR-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 oilfired EGU has a FGD system installed, eliminating the potential basis for the use of compliance with an SO2 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

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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 We are also not

require testing for radionuclides.

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 9,866). 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
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existing NSPS to avoid duplicating requirements to the extent possible. 2. CAA section 112 EPA has previously developed other non-EGU combustionrelated 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 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 10,512; 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
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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 simplecycle 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
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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
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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
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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 input156 (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.
156

Thus, for example, a biomass-fired EGU,

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).
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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. comment on the use of these definitions. EPA solicits

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). 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
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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 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. 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).
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Such

A

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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

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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
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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. contrast, the unit would be subject to this rule if it meets the definition of EGU. If the unit combusts solid By

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
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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,
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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 11 and 12 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,
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which we developed based on unit type. We are proposing that new or existing EGUs are “coalfired” 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 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

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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 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 oilderived 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
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.
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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 Total particulate matter 0.030 lb/MMBtu (0.30 lb/MWh) 0.030 lb/MMBtu (0.30 lb/MWh) 0.050 lb/MMBtu (0.30 lb/MWh) 0.20 lb/MMBtu (2.0 lb/MWh) 0.050 lb/MWh Hydrogen chloride 0.0020 lb/MMBtu (0.020 lb/MWh) 0.0020 lb/MMBtu (0.020 lb/MWh) 0.00050 lb/MMBtu (0.0030 lb/MWh) 0.0050 lb/MMBtu (0.080 lb/MWh) 0.30 lb/GWh Mercury 1.0 lb/TBtu (0.0008 lb/GWh) 11.0 lb/TBtu (0.20 lb/GWh) 4.0 lb/TBtu* (0.040 lb/GWh*) 3.0 lb/TBtu (0.020 lb/GWh) 0.20 lb/TBtu (0.0020 lb/GWh) 0.000010 lb/GWh 0.040 lb/GWh

Subcategory Existing coalfired unit designed for coal > 8,300 Btu/lb Existing coalfired unit designed for coal < 8,300 Btu/lb Existing - IGCC

Existing – Solid oilderived New coal-fired unit designed for coal > 8,300 Btu/lb New coal-fired unit designed for coal < 8,300 Btu/lb New – IGCC

0.050 lb/MWh

0.30 lb/GWh

0.050 lb/MWh*

0.30 lb/GWh*

New – Solid 0.050 lb/MWh 0.00030 oil-derived lb/MWh Note: lb/MMBtu = pounds pollutant per million British

0.000010 lb/GWh* 0.0020 lb/GWh

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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 Total HAP metals* 0.000030 lb/MMBtu (0.00030 lb/MWh) 0.00040 lb/MWh Hydrogen chloride 0.00030 lb/MMBtu (0.0030 lb/MWh) 0.00050 lb/MWh Hydrogen fluoride 0.00020 lb/MMBtu (0.0020 lb/MWh) 0.00050 lb/MWh

Subcategory Existing – Liquid oil

New – Liquid oil * 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

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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 coalfired 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. 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
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an alternate to PM for all subcategories except liquid oilfired); 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 D.C. 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 (D.C. Cir. 2008), cert. denied, 130 S. Ct. 1735 (U.S. 2010). Specifically, the D.C. 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
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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 EGUs, especially solid

boiler operating day averages.

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
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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 (D.C. Cir. 2004), the D.C. 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,

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590 F.2d 1011, 1058 (D.C. Cir. 1978) (“In the nature of things, no general limit, individual permit, or even any upset provision can anticipate all upset situations. After

a certain point, the transgression of regulatory limits caused by ‘uncontrollable acts of third parties,’ such as strikes, sabotage, operator intoxication or insanity, and a variety of other eventualities, must be a matter for the administrative exercise of case-by-case enforcement discretion, not for specification in advance by regulation.”) 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
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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.” (definition of malfunction). Finally, EPA recognizes that even equipment that is properly designed and maintained can sometimes fail and
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See 40 CFR 63.2

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that such failure can sometimes cause an exceedance of the relevant emission standard. Implementation Plans: (See, e.g., State

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. 22.24. See 40 CFR

The criteria ensure that the affirmative defense is

available only where the event that causes an exceedance of the emission limit meets the narrow definition of malfunction in 40 CFR 63.2 (sudden, infrequent, not
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reasonable 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.

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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
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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°C (320 ± 25°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
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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 For units with or

be used to determine initial compliance.

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
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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 For non-Hg HAP

testing would be conducted as follows. metals, use EPA Method 29.

For Hg, conduct emissions For acid gases,

testing using EPA Method 29 or Method 30B.

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
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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: (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

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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
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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
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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

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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);
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(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
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(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. appropriateness of this period. J. 1. What are the continuous compliance requirements? 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 We seek comment on the

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 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

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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 oilderived 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.
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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
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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
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for acid gases.

First, an SO2 or an HCl CEMS could be We are proposing that the SO2

installed and certified.

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 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
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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 HAP metals testing would be

require testing as follows.

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
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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 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
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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
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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
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mass.

The units were then ranked by their annual Hg mass At the point in the rankings where the

emissions.

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
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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,

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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 Semiannual hard copy

would be followed for on-going QA.

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
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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 75compliant 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 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.
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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
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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.
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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. 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

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
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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
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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 The

30 days after the end of each calendar quarter.

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 1) the parameter

concentration includes data fields for:

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
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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 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
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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. 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,
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We solicit comment on this proposed

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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 CEMS and sorbent trap

Hg continuous monitoring options: 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. bias test would not be required. The performance A

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 3level 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
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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 Bias

would be the same as for the RATAs of the Hg CEMS.

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
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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 However, for the sorbent trap

reported in all cases.

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
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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 userfriendly 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
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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 §63.9(h) of the General Provisions. This 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 §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,

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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

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emission limit and each operating limit (i.e., deviations from this proposed rule). (4) (5) Daily hours of operation by each source. 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.
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(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) (2) Notifications required by the General Provisions. 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.
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(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
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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. description of the ERT can be found at http://www.epa.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 A

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_tool.html. We believe

that industry would benefit from this proposed approach to
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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 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

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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.
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In

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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
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ease of implementation, and the transparency to the public of the information.. V. A. Rationale for this Proposed NESHAP 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
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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: fired and oil-fired. coal-

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 coalfired 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
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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 oilfired 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 An additional

the capacity and efficiency of the EGU.

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. emissions. EGUs emit a number of different types of HAP Organic HAP are formed from incomplete

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combustion and are primarily influenced by the design and operation of the unit. The degree of combustion may be time,

greatly influenced by three general factors: 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 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, wallThis document is a prepublication version, signed by EPA Administrator, Lisa P. Jackson on 03/16/2011. We have taken steps to ensure the accuracy of this version, but it is not the official version.

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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
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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. 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 No

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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
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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
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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.
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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 fuelborne 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. We are proposing numerical emission rate limitations as a mass of pollutant emitted per megawatt- or gigawatthour (MWh or GWh) gross output from the EGU for the fuelborne 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.,
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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 We chose to look at Hg

controlled with PM controls.

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
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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
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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 The facility is equipped The

coal, natural gas, and fuel oil.

with low NOX burners and an SCR unit for NOX control. 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.
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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 The potential

were examined during the testing program.

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
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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 Sb –

metals was (for all coals and all configurations):

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. 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 When

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 When subbituminous

primary PM control device was variable.

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coal was fired, the control of Se through the ESP was greater than 99 percent. When lignite was fired, the However,

control through the ESP was about 80 percent.

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 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
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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 “nonHg 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

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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 The control efficiency for SO2 for the runs was

value.)

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
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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 Under

used as an indicator of combustion conditions.

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).
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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
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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 Most, if

metallic HAP, we chose to use PM as a surrogate.

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
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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 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
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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 Therefore, HCl

controls for other inorganic acid gas HAP.

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,
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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 nondioxin/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.
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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
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rule.

In the case of the Boiler NESHAP, the MDL issue was For that rulemaking, the required

with the organic HAP.

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
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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,
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may be inconsistent with the D.C. 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 quality health and environmental impacts and energy requirements, determines is achievable for each category. For existing

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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 ICR158 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
158

Earlier data were not used due to concerns related to changes in test and analytical methods.
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percent of sources. 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
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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 D.C. 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 (D.C. 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
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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
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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
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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. kurtosis statistic (K) characterizes the degree of peakedness or flatness of a given data distribution in comparison to a normal distribution. data have a kurtosis of 0. Normally distributed The

A kurtosis statistic that is

greater (less) than 0 indicates a relatively peaked (flat) distribution. Further, the standard error of the kurtosis

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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.
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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:

Where: n = the number of test runs m = the number of test runs in the compliance average = mean of the data from top performing sources calculated as 1 n x = ∑ xi n i =1 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 s2 = 1 ⎧N 2⎫ ⎨∑ ( xi − x ) ⎬ n − 1 ⎩ i =1 ⎭

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 onetailed 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
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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, s2, 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. as: The UPL equation for this case was calculated

⎛1 1⎞ x + tdf ,.99 s 2 ⎜ + ⎟ ⎝ N m⎠ 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 ith source
n = N + ∑ ni
i =1 N

the ith source yi = past information (e.g., stack average) for the ith source m = the number of future test runs in the compliance average = mean of the data from the top performing sources calculated as

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

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x=

1 N

∑x
i =1

N

i

x is the grand mean (mean of the current and past information from the top performing sources) calculated as
N ni ⎞ 1⎛ N ⎜ ∑ xi + ∑∑ yi ⎟ n ⎝ i =1 i =1 j =1 ⎠

x=

s2 = variance calculated as
N ni 2⎫ 2 1 ⎧N s = ⎨∑ ( xi − x ) + ∑∑ ( yij − x ) ⎬ n − 1 ⎩ i =1 i =1 j =1 ⎭ 2

tdf,.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):

UPL = e

ˆ μ + σˆ2

2

+

2 ˆ2 ˆ z.99 σ4 ⎞ ˆ 2 ˆ 2 ⎛σ + me 2 μ +σˆ (eσˆ − 1) + m2 e 2 μ +σˆ ⎜ ⎟ m ⎝ n 2(n − 1) ⎠

Where: m = the number of test runs in the compliance average n = the number of test runs ˆ μ = the average of the log transformed data from the top performing sources calculated as
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∑ ˆ μ=

n i =1

log ( yi ) n

ˆ σ 2 = the variance estimate of the log transformed data from the top performing sources calculated as

ˆ σ

2

ˆ ∑ ( log ( y ) − μ ) =
n i =1 i

2

n −1

z99 = the 99th-percentile of the log-normal distribution estimated using the trapezoidal rule approach from the following equation

∫

z.99

0

⎛ ( β 2 z − 3) ( 3 − 6 z 2 + z 4 ) ⎞ β ⎜1 − 1z ( 3 z − z 3 ) + ⎟ φ ( z ) = .99 ⎜ ⎟ 6 24 ⎝ ⎠

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) + (99THPERCENTILE 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^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%))^2/(2*(n-1)))). The 99th 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
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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 Another view of this

positive or the alpha, Type I, error.

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
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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

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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

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

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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). 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

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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

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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-tosite differences for the best 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 tfactor, 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.
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1.

Determination of MACT for the Fuel-borne HAP for

Existing Sources In developing the proposed MACT floor for the fuelborne 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. Parameter No. of sources in subcategory PM 1,091 HCl 1,091 Mercury 1,061

Subcategory Coal-fired unit designed for coal > 8,300 Btu/lb

No. in MACT floor Avg. of top 12% 99% UPL of top 12% No. of sources in subcategory

Coal-fired unit

131 0.02 lb/MMBtu 0.030 lb/MMBtu 1,091

131 0.0003 lb/MMBtu 0.0020 lb/MMBtu 1,091

40 0.01 lb/TBtu 1.0 lb/TBtu 30

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designed for coal < 8,300 Btu/lb No. in MACT floor Avg. of top 12% 131 0.02 lb/MMBtu 131 0.0003 lb/MMBtu 2 1* 1 lb/TBtu (1 lb/TBtu* ) 11.0 lb/TBtu (4.0 lb/TBtu* ) 2 2 0.9 lb/TBtu 3.0 lb/TBtu 10 5 0.09 lb/TBtu 0.20 lb/TBtu Mercury 154 7 NA NA

99% UPL of top 12%

0.030 lb/MMBtu

0.0020 lb/MMBtu

IGCC

No. of sources in subcategory No. in MACT floor Avg. 99% UPL

2 2 0.03 lb/MMBtu 0.050 lb/MMBtu 10 5 0.04 lb/MMBtu 0.20 lb/MMBtu Total metals** 154

2 2 0.0002 lb/MMBtu 0.00050 lb/MMBtu 10 5 0.002 lb/MMBtu 0.0050 lb/MMBtu HCl 154

Solid oilderived

No. of sources in subcategory No. in MACT floor Avg. of top 5 99% UPL of top 5

Liquid oil

7 7 0.00002 0.0001 lb/MMBtu lb/MMBtu 99% UPL of top 0.000030 0.00030 12% lb/MMBtu lb/MMBtu * Beyond-the-floor limit as discussed elsewhere. ** Includes Hg. NA = Not applicable

No. of sources in subcategory No. in MACT floor Avg. of top 12%

For the “Coal-fired unit designed for coal < 8,300
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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 existingsource 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
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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 oilfired units. In this regard, we request additional Hg Although we have some

emissions data from oil-fired EGUs.

data, additional 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
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technological and economic limitations.” As noted earlier, the significant majority of the measured emissions from EGUs of dioxin/furan and nondioxin/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
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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 The

formed from incomplete combustion of the fuel.

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
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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
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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 First,

was not an appropriate beyond-the-floor option.

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
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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
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a calorific value (moist, mineral matter-free basis) of 19,305 kJ/kg (8,300 Btu/lb) or less in a EGU with a heightto-depth ratio of 3.82 or greater. The proposed emission This

limit is 4 lb/TBtu for existing EGUs in this class.

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 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
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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. 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 Non-

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

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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. 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 EPA solicits comment on

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-thefloor 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.
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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 Similarly, ACI

been demonstrated on liquid oil-fired EGUs.

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

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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
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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 However, EPA may not consider costs or EPA must

for new units.

other impacts in determining the MACT floor.

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

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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 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 bestcontrolled 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
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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
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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. Parameter Avg. of top performer PM 0.03 lb/MWh HCl 0.2 lb/GWh Mercury 0.00001 lb/GWh

Subcategory Coal-fired unit designed for coal > 8,300 Btu/lb

Coal-fired unit designed for coal < 8,300 Btu/lb

99% UPL of top performer (test runs) Avg. of top performer

0.050 lb/MWh 0.03 lb/MWh

0.30 lb/GWh 0.2 lb/GWh

0.000010 lb/GWh 0.02 lb/GWh

IGCC

Solid oilderived

99% UPL of top performer(te st runs) Avg. of top performer 99% UPL of top performer(te st runs) Avg. of top performer 99% UPL of top

0.050 lb/MWh N/A 0.050 lb/MWh* 0.04 lb/MWh 0.050 lb/MWh

0.30 lb/GWh N/A 0.30 lb/GWh* 0.0003 lb/MWh 0.00030 lb/MWh

0.040 lb/GWh N/A 0.000010 lb/GWh* 0.0007 lb/GWh 0.0020 lb/GWh

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performer(te st runs) Total metals** 0.00009 lb/MMBtu 0.00040 lb/MMBtu HCl Mercury NA NA

Avg. of top 0.0002 performer lb/MWh 99% UPL of 0.00050 top lb/MWh performer(te st runs) * Beyond-the-floor as discussed elsewhere. ** Includes Hg. NA = Not applicable 2. Determination of the Work Practice Standard

Liquid oil

We are proposing a work practice standards for nondioxin/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 nondioxin/furan organic and dioxin/furan organic HAP for new EGUs.
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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 Thus, this

gas supplies are not available in some areas.

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

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addition, 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
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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
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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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. comment on this approach. EPA solicits

Commenters should provide data

that support their comment, including costs, emissions data, or engineering analyses. Similarly, for the reasons discussed earlier for existing EGUs, EPA is not proposing any other beyond-thefloor 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. 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 Comments

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

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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 HCN162 (because if it were

regulated under CAA section 112(d)(4), HCl may no longer be the appropriate surrogate for these other HAP).163 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. As a general matter, CAA section 112(d) requires MACT standards at least as stringent as the MACT floor to be set
162

This

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 doseresponse relationship.
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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. 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
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Where

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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 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
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emissions standards for other major source categories, including the Boiler NESHAP issued in 2004, which was vacated on other grounds by the D.C. Circuit Court. In the

Pulp and Paper NESHAP (63 FR 18,765; April 15, 1998), and Lime Manufacturing NESHAP (67 FR 78,054; 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,
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Commercial, and Institutional Boilers, (75 FR 32,005; 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 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 In the case of HCl, this

chronic respiratory toxicity.

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 (μg/m3).
164

An RfC is defined as an estimate

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.
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(with uncertainty spanning perhaps an order of magnitude) of a continuous inhalation exposure to the human population (including sensitive subgroups165) that is likely to be without an appreciable risk of deleterious effects during a lifetime. The development of the RfC for HCl reflected It did not

data only on its chronic respiratory toxicity.

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. With respect to the potential health effects of HCl, we note the following: “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/m3). 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.
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165

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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 The one occupational study of which we

carcinogenicity.

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. Hydrogen Chloride, http://www.oehha.ca.gov/air/hot_spots/2008/AppendixD2_final .pdf#page=112 EPA, 2001). In addition, we note that Acute Toxicity Summary for

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
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.
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acute exposures will not pose any health concerns, and; 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
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hydrochloric acid could exacerbate these impacts.

Recent

research168 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). 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 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.
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.
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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 Although NESHAP

with substantial public health benefits.

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.

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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
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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. K.
170

How did we select the compliance requirements?

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).
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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 in We selected these requirements

elsewhere in this preamble.

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
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periodic stack testing.

These requirements are found in For

proposed Appendix A to 40 CFR part 63, subpart UUUUU.

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
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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 1,786, 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. CEMS monitoring, initial costs were estimated to be $261,000 per unit and annualized costs were estimated to be $91,000 per unit. We determined that requiring PM CEMS for For PM

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
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testing. TABLE 14. COST INFORMATION Initial Annual costs, costs, $K $K Metals 261 91 61 109 59 114 Acid Gases 232 233 10 9 Mercury Hg CEMS Sorbent traps 271 23 110 128 Minimum of 52 traps and analysis per year 66 57 144 143 Plus material costs None if existing CEMS used

PM CEMS Fabric filter ESP SO2 CEMS HCl CEMS Dry sorbent injection Wet scrubber

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 American

voluntary consensus standards were identified:

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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
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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 4hour 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
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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 If a

not required to conduct performance stack tests.

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
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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
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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
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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
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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

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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
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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 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 straightforward 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
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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 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.
171

See section

Hazardous Organic NESHAP (59 FR 19,425; April 22, 1994).
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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
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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
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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
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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 3year window.172
172

Notably, EPA does not project use of wet

In a letter to Senator Carper dated November 3, 2010 (http://www.icac.com/files/public/ICAC_Carper_Response_1103 10.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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scrubbing technology to meet the requirements of this proposed rule and that is the technology that typically takes a longer time to install. 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). controls such as ACI. Other companies may use supplemental 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 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

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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
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an additional two shoulder periods to schedule outages. also provides additional opportunity to spread complex outages over multiple outage periods. EPA believes that

It

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 sitespecific challenges that may arise related to sourcespecific 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
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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

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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
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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 Within 4 years

MWs of capacity in demand side resources.

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. EPA also examined the impact on reliability of unit outages to install control equipment.
173

Because these

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%20 Sotkiewicz-%20Panel%202_0.pdf, slide 6 174 Ibid – slide 5
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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 (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
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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 Cinergy Press Release, September 2nd, 2004, “Cinergy Operating Companies to Reduce Power Plant Emissions, Improve Air Quality” 176 ICAC
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175

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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 This will

compliance options based on the proposed rule.

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. 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,

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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 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
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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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
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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 decisionmakers 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,
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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 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
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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 costminimization. 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
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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

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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
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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
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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.,
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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 (HB1464)). 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 timeframes for 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

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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
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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
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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
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to comply with the chlorine or Hg fuel input option. would need to keep records of the calculations and

You

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 EPAapproved 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. Alternate 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
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preamble. TABLE 15. ALTERNATE EMISSION LIMITATIONS FOR EXISTING COAL- AND OIL-FIRED EGUS Coalfired unit designed for coal > 8,300 Btu/lb 0.20 lb/MMBtu (2.0 lb/MWh) 0.000040 lb/MMBtu (0.00040 lb/MWh) 0.60 lb/TBtu (0.0060 lb/GWh) 2.0 lb/TBtu (0.020 lb/GWh) 0.20 lb/TBtu (0.0020 lb/GWh) 0.30 lb/TBtu (0.0030 lb/GWh) 3.0 lb/TBtu (0.030 lb/GWh) 0.80 lb/TBtu (0.0080 lb/GWh) 2.0 Coalfired unit designed for coal < 8,300 Btu/lb 0.20 lb/MMBtu (2.0 lb/MWh) 0.000040 lb/MMBtu (0.00040 lb/MWh) 0.60 lb/TBtu (0.0060 lb/GWh) 2.0 lb/TBtu (0.020 lb/GWh) 0.20 lb/TBtu (0.0020 lb/GWh) 0.30 lb/TBtu (0.0030 lb/GWh) 3.0 lb/TBtu (0.030 lb/GWh) 0.80 lb/TBtu (0.0080 lb/GWh) 2.0 IGCC, lb/TBtu (lb/GWh) Liquid oil, lb/TBtu (lb/GWh) Solid oilderived

Subcategory

SO2

NA

NA

Total nonHg metals Antimony, Sb Arsenic, As

5.0 (0.050)

NA

0.40 0.20 (0.0040) (0.0030) 2.0 (0.020) 0.60 (0.0070)

Beryllium, Be Cadmium, Cd

0.030 0.060 (0.0030) (0.00070 ) 0.20 0.10 (0.0020) (0.0020) 3.0 (0.020) 0.60 (0.0040) 29.0 2.0 (0.020) 3.0 (0.020) 2.0

Chromium, Cr Cobalt, Co

Lead, Pb

0.40 lb/MMBtu (5.0 lb/MWh) 0.000050 lb/MMBtu (1.0 lb/MWh) 0.40 lb/TBtu (0.0070 lb/GWh) 0.40 lb/TBtu (0.0040 lb/GWh) 0.070 lb/TBtu (0.00070 lb/GWh) 0.40 lb/TBtu (0.0040 lb/GWh) 2.0 lb/TBtu (0.020 lb/GWh) 2.0 lb/TBtu (0.020 lb/GWh) 11.0

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Manganese, Mn Mercury, Hg

lb/TBtu (0.020 lb/GWh) 5.0 lb/TBtu (0.050 lb/GWh NA

lb/TBtu (0.020 lb/GWh) 5.0 lb/TBtu (0.050 lb/GWh NA

lb/MMBtu (0.30 lb/MWh) 3.0 (0.020) NA

(0.030) 5.0 (0.060) 0.050 lb/TBtu (0.00070 lb/GWh) 8.0 (0.080) 2.0 (0.020)

lb/TBtu (0.020 lb/GWh) 3.0 lb/TBtu (0.040 lb/GWh) NA

4.0 lb/TBtu (0.040 lb/GWh) Selenium, 6.0 Se lb/TBtu (0.060 lb/GWh) NA = Not applicable TABLE 16.

Nickel, Ni

4.0 lb/TBtu (0.040 lb/GWh) 6.0 lb/TBtu (0.060 lb/GWh)

5.0 (0.050) 22.0 (0.20)

9.0 lb/TBtu (0.090 lb/GWh) 2.0 lb/TBtu (0.020 lb/GWh)

ALTERNATE EMISSION LIMITATIONS FOR NEW COAL- AND OIL-FIRED EGUS Coalfired unit designed for coal > 8,300 Btu/lb 0.40 lb/MWh 0.000040 lb/MWh 0.000080 lb/GWh 0.00020 lb/GWh 0.000030 lb/GWh 0.00040 lb/GWh 0.060 lb/GWh CoalIGCC* fired unit designed for coal < 8,300 Btu/lb 0.40 0.40 lb/MWh lb/MWh 0.000040 0.000040 lb/MWh lb/MWh 0.000080 0.000080 lb/GWh lb/GWh 0.00020 0.00020 lb/GWh lb/GWh 0.000030 0.000030 lb/GWh lb/GWh 0.00040 0.00040 lb/GWh lb/GWh 0.060 0.060 lb/GWh lb/GWh Liquid oil, lb/GWh Solid oilderived

Subcategory

SO2 Total metals Antimony, Sb Arsenic, As Beryllium, Be Cadmium, Cd Chromium, Cr

NA NA 0.0020 0.0020 0.00070 0.00040 0.020

0.40 lb/MWh 0.00020 lb/MWh 0.00090 lb/GWh 0.0020 lb/GWh 0.000080 lb/GWh 0.0070 lb/GWh 0.0060 lb/GWh

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Cobalt, Co Lead, Pb Mercury, Hg Manganese, Mn Nickel, Ni

0.00080 lb/GWh 0.00090 lb/GWh NA

0.00080 lb/GWh 0.00090 lb/GWh NA

0.00080 lb/GWh 0.00090 lb/GWh NA

0.0060 0.0060 0.00010 lb/GWh 0.030

0.0020 lb/GWh 0.020 lb/GWh NA 0.0070 lb/GWh 0.0070 lb/GWh 0.00090 lb/GWh

0.0040 0.0040 0.0040 lb/GWh lb/GWh lb/GWh 0.0040 0.0040 0.0040 0.040 lb/GWh lb/GWh lb/GWh Selenium, 0.030 0.030 0.030 0.0040 Se lb/GWh lb/GWh 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

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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 oilfired 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. A. Background Information on the Proposed NSPS 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)

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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). 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-commercialinstitutional 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
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(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(D.C. 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
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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 [INSERT THE DATE 1 DAY AFTER THE DATE OF PUBLICATION OF THIS PROPOSED RULE IN THE FEDERAL REGISTER]. 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 [INSERT DATE OF PUBLICATION OF THE PROPOSED AMENDMENTS IN THE FEDERAL REGISTER]. 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.
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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
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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
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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
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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 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 are used to also control other pollutants such as SO2, HCl, and Hg. A combined PM standard allows for optimal Thus, with

design and operation of the control equipment.

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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
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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
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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 [INSERT DATE OF PUBLICATION OF THE PROPOSED AMENDMENTS IN THE FEDERAL REGISTER] 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 [INSERT DATE OF PUBLICATION OF THE PROPOSED AMENDMENTS IN THE FEDERAL REGISTER] 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.
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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.
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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-ofcontrol 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?
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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 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
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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. amendments are as follows. We are proposing several definitional changes. First, The additional significant

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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 The proposed change would thus

reduction in emissions.

reduce regulatory burden without decreasing environmental
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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, As a

CAMR was vacated by the D.C. Circuit Court in 2008.

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
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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 [INSERT DATE OF PUBLICATION OF THE PROPOSED AMENDMENTS IN THE FEDERAL REGISTER]. 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
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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
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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 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
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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
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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
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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
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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 The

units to compare the relationship between NOX and CO.

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
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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 (D.C. Cir. 1978) (“In the nature of things, no general limit, individual permit, or even any upset provision can anticipate all upset situations. After

a certain point, the transgression of regulatory limits caused by ‘uncontrollable acts of third parties,’ such as strikes, sabotage, operator intoxication or insanity, and a variety of other eventualities, must be a matter for the administrative exercise of case-by-case enforcement discretion, not for specification in advance by regulation.”) and, therefore, any emissions that occur at such times do not need to be factored into development of CAA section 111 standards Further, it is reasonable to interpret CAA section 111 as not requiring EPA to account for malfunctions in setting
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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 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
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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.” (definition of malfunction). Finally, EPA recognizes that even equipment that is properly designed and maintained can sometimes fail. Such 40 CFR 60.2

failure can sometimes cause an exceedance of the relevant emission standard. (See, e.g., State Implementation Plans: During Malfunctions,

Policy Regarding Excessive Emissions

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

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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. 22.24). (See 40 CFR

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
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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. less developed. However, controls for condensable PM are 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
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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

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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 Based on

and FGD in combination with both DSI and a WESP.

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 We are soliciting comments on

is 7.0 ng/J (0.055 lb/MWh).

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
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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. 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 fluidizedbed, and, if necessary, installing additional postcombustion controls. Owners/operators of steam generating

units using PC combustion technology can use postcombustion 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
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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 coalfired EGUs. TABLE 17: SO2 EMISSIONS PERFORMANCE DATA Time Period Maximum 30Day SO2 Emissions Rate (lb/MWh) 1.03 1.45 1.01 0.97 1.83 1.26 1.45 1.08 0.31 0.37 0.16 0.09 0.13 1.14 1.15 Minimum 30Day Percent SO2 Reduction 97.4 96.7 97.7 98.2 96.9 98.0 96.5 97.7 97.7 97.4 98.2 99.0 98.5 97.6 97.6

Facility

Cayuga 1 Harrison 1 Harrison 2 Harrison 3 HL Spurlock 1 HL Spurlock 2 HL Spurlock 3 HL Spurlock 4 Wansley 1 Wansley 2 Iatan 1 Jeffrey 2 Jeffrey 3 Trimble County 1 Mountaineer 1

12/08 01/06 01/06 01/06 06/09 11/08 01/09 01/09 02/09 05/09 04/09 05/09 04/09 01/05

– – – – – – – – – – – – –

12/09 01/09 01/09 01/09 12/09 12/09 12/09 12/09 12/09 12/09 12/09 12/09 12/09 12/09

05/07 – 12/09

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

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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 Jeffery

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
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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 In Service Date 2008 2008 2008 2008 2007 2007 2006 2005 Maximum 30Day SO2 Emissions Rate (lb/MWh) 0.61 1.02 0.56 0.95 0.73 1.06 1.04 1.45

Facility Weston 4 Cross 4 TS Power Plant 1 Wygen II Walter Scott Jr. Energy Center 4 Cross 3 Springerville TS3 HL Spurlock 3

SO2 Control Technology Lime-based Spray Dryer Wet Limestone FGD Lime-based Spray Dryer Lime-based Spray Dryer Lime-based Spray Dryer Wet Limestone FGD Lime-based Spray Dryer Fluidized Bed Limestone Injection + Lime Injection

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

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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 lowersulfur 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. 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 In

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
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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. 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

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 limestonebased scrubber, lime production facilities have relatively concentrated CO2 streams. Capture and storage of CO2 at the

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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
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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
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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 9,866), 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.
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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. TABLE 19: NOX PERFORMANCE DATA Time Period 01/05 – 12/09 04/07 – 12/09 06/07 – 12/09 06/08 – 12/09 01/09 – 12/09 01/09 – 12/09 01/09 – 12/09 Maximum 30-Day NOX Emissions Rate (lb/MWh) 0.70 0.58 0.65 0.70 0.67 0.38 0.46 Boiler Type & Primary Coal Rank PC, Sub PC, Sub PC, Bit PC, Bit PC, Bit PC, Bit PC, Bit

Facility Havana 9 Walter Scott Jr. 4 Mirant Morgantown 1 Mirant Morgantown 2 Roxboro 2 Cardinal 1 Cardinal 2

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01/09 – 12/09 Muskingum River 01/08 – 5 12/09 John E Amos 06/09 – 12/09 Mitchell 1 01/09 – 12/09 Mitchell 2 01/09 – 12/09 Weston 4 07/08 – 12/09 H L Spurlock 4 05/09 – 12/09 Wansley 1 02/09 – 12/09 Wansley 2 01/09 – 12/09 Nebraska City 2 05/09 – 12/09 TS Power 1 07/08 – 12/09 Note: PC = pulverized coal CFB = circulating fluidized bed Sub = subbituminous coal Bit = bituminous coal

Cardinal 3

0.45 0.60 0.62 0.59 0.54 0.48 0.67 0.67 0.59 0.60 0.49

PC, Bit PC, Bit PC, Bit PC, Bit PC, Bit PC, Sub CFB, Bit PC, Bit PC, Bit PC, Sub PC, Sub

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
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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 However, high levels of

used to control CO emissions.

excess air increase NOX emissions. The proposed BDT for NOX is combustion controls plus the application of SCR. However, there are several

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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 From an

significant unburned carbon in the fly ash.

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

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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. TABLE 20. NOX/CO PERFORMANCE DATA Maximum Maximum 30-Day 30-Day NOX + CO NOX/CO Emissions Emissions Rate Rate (lb/MWh) (lb/MWh) 1.1 0.89/0.29 1.1 0.93/0.46 Boiler Type & Primary Coal Rank CFB, PC CFB, PC

Facility

Time Period 01/05 – 12/09 01/05 –

Northside 1 Northside 2

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12/09 04/07 – 0.95 12/09 09/05 – 1.1 12/09 WA Parish 6 06/05 – 1.2 12/09 WA Parish 7 06/05 – 1.8 12/09 WA Parish 8 04/06 – 1.5 12/09 HL Spurlock 3 01/09 – 1.4 12/09 HL Spurlock 4 05/09 – 1.4 12/09 TS Power 1 04/08 – 0.80 12/09 Note: PC = pulverized coal or petroleum CFB = circulating fluidized bed Sub = subbituminous coal Walter Scott, Jr. 4 WA Parish 5

0.58/0.42 0.66/0.62 0.76/0.81 0.53/1.4 0.42/1.1 0.83/0.61 0.67/0.70 0.49/0.47 coke

PC, Sub PC, Sub PC, Sub PC, Sub PC, Sub CFB, Bit CFB, Bit PC, Sub

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.
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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
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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. 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.
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4.

Commercial Demonstration Permit The commercial demonstration permit section of the EGU

NSPS was included in the original rulemaking in 1979 (44 FR 33,580) 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 33,580.) 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 D.C. Circuit Court’s opinion in Essex Chemical Corp. v.
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Ruckelshaus, 486 F. 2d 42 (D.C. 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 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
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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

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Airborne ProcessTM, the CEFCO process, Eco Power’s COMPLY 2000, Powerspan’s ECO®, ReACTTM, Skyonic’s SkyMine®, TOPSØE SNOXTM, 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) multipollutant 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

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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
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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

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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.
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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 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
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(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 outputbased 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
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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 a 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
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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 However, the

would be consistent with the IB NSPS.

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
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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 These potential

amendments that are under consideration. 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.
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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
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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 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
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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
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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
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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,
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Page 532 of 946

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.
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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

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Page 534 of 946

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 We are also requesting comment

between 10 to 20 percent.

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 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
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Page 535 of 946

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
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Page 536 of 946

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 This

references to MSW in 40 CFR part 60, subpart Db.

would simplify compliance and readability of the rule without increasing emissions to the environment.
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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
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Page 538 of 946

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
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Page 539 of 946

amendments, and we have concluded that there are no costs or benefits associated with these amendments. 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 We are

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
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Page 540 of 946

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 coalfired 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/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
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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. A. Impacts of These Proposed Rules 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. TABLE 21. See Table 21.

SUMMARY OF POWER SECTOR EMISSIONS REDUCTIONS (TPY) HCl (thousa nd tons) 78 10 -68 PM2.5 (thousa nd tons) 286 202 -83.2 CO2 (millio n metric tonnes) 2,243 2,219 -24.2

SO2 (millio n tons) Base Case Proposed Toxics Rule Change 3.9 1.8 -2.1

NOX (millio n tons) 2.0 1.9 -0.1

Mercury (tons) 29 6 -23.0

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Page 542 of 946

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
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Page 543 of 946

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
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Page 544 of 946

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 However this rule

largely outside of EPA’s direct control.

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
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Page 545 of 946

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 and 2020 respectively) so that their impacts continue through 2050. Table 22 below gives the

electricity demand reductions that these two policies would yield. TABLE 22. (all in TWh) Ratepayerfunded EE Programs % of U.S. Demand
179

ENERGY EFFICIENCY SENSITIVITY RESULTS: ELECTRICITY DEMAND REDUCTIONS 2009 2012 2015 2020 2030 2040 2050

59 1.5%

110 2.7%

174 4.1%

198 4.2%

198 3.9%

198 3.6%

The Shifting Landscape of Ratepayer Funded Energy Efficiency in the U.S., Galen Barbose et. al., October 2009, Lawrence Berkeley National Laboratory, LBNL-2258E
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Federal Appliance Standards % of U.S. Demand Total EE Demand Reductions % of U.S. Demand U.S. Electricity Demand (EPA Reference) Average Annual Growth Rate (2009 to 20xx) Net Demand after EE Average Annual Growth Rate (2009 to 20xx)

0 0.0%

6 0.2%

52 1.2%

112 2.4%

114 2.2%

124 2.2%

59 1.5%

117 2.9%

226 5.3%

310 6.6%

312 6.1%

322 5.8%

3,838

4,043 4,086 4,302 4,703 5,113 5,568

1.05% 1.04% 0.97% 0.93% 0.91%

3,838 3,984 3,969 4,076 4,392 4,801 5,246 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
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Page 547 of 946

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 EE Base Base + EE Toxics Rule Toxics Rule + EE 1. Increment (Base to Base + EE) 2. Increment (Toxics Rule to Toxics Rule + EE) 3. Increment (Base to Toxics Rule) 4. Increment (Base + EE to Toxics rule + EE) 5. Increment (Base to Toxics Rule) to (Base + EE to Toxics Rule + EE) 6. Increment (Base to Toxics Rule + EE) 2015 144 142 155 153 -2 -2 11 11 0 9 2020 155 150 165 159 -5 -6 10 9 -1 4 2030 200 190 210 199 -11 -11 10 9 -1 -1

TOTAL COSTS (billion 2007$) -- IPM + Total

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
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Page 548 of 946

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. reductions increase over time. The cost

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
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Page 549 of 946

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. 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 Toxic 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 retirements in 2020. These results are shown in Table 24 below. TABLE 24. EFFECT OF ENERGY EFFICIENCY ON RETIREMENTS 2015 27 (5) 38 (12) 35 (15) 47 (25) 2020 27 (5) 54 (12) 35 (14) 60 (24) 2030 27 (5) 53 (12) 35 (14) 60 (24)

Retirements Grand Total & (Coal) (GW) Base Base + EE Toxics Rule Toxics Rule + EE
180

Source:

EPA’s Retail Electricity Price Model.

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1. Increment (Base to Base + EE) 2. Increment (Toxics Rule to Toxics Rule + EE) 3. Increment (Base to Toxics Rule) 4. Increment (Base + EE to Toxics rule + EE) 5. Increment (Base to Toxics Rule) to (Base + EE to Toxics Rule + EE) 6. Increment (Base to Toxics Rule + EE)

11 (7) 11 (10) 9 (10) 9 (13) 0 (3.0) 20 (20)

27 (7) 25 (10) 8 (9) 6 (12) -2 (3) 33 (19)

26 (7) 24 (10) 8 (9) 6 (12) -2 )3) 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 As a result, with

lower levels of electricity generation.

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
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Page 551 of 946

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 These

representative unit costs for each control option.

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
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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 + FF Total Capit (2007 al $MM) FOM VOM 2015 Annua l Capit al + FOM + VOM Cost HCL Share Hg PM2.5 SO2 Total Annua l Costs , 2015 (2007 $MM) HCL Hg PM2.5 SO2 TOTAL 1,421 252 377 2,050 DSI FF Scrub Waste Total ber Coal Upgra FGD de 1,498 669 94 5,201 45 627 2,173 0 0 669 20 66 179 431 2,416 8,048 ACI

428 71 1,241 1,740

1,092 41 105 1,238

29% 10% 32% 29% 588 205 654 603 2,050

56% 0% 0% 44% 979 0 0 761 1,740

0% 10% 90% 0% 0 124 1,114 0 1,238

0% 51% 49% 0% 0 1,106 1,067 0 2,173

52% 0% 0% 48% 347 0 0 322 669

29% 10% 32% 29% 51 18 57 53 179 1,965 1,453 2,892 1,739 8,048

Capit al + FOM + VOM Costs

Fuel Cost

Total Cost

Share of total Cost

Capit al Share

Tons Reduc ed

$/ton ($/lb for Hg)

Gener al Range Of Costs From Other

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Page 553 of 946

MACT Rules Acid Gasse s (HCl + HCN + HF) Hg 1,965 1,064 3,029 24% 37% 106,0 38 $18,5 $2500 29 $55,0 00 $40,4 $1250 28 $55,2 00 $34,7 $1600 42 $55,0 00 $848 $540 $5100

1,453

825

2,277

18%

49%

18

PM2.5

2,892

357

3,249

36%

74%

83,24 6 2,050 ,871

SO2 Total D. 1.

1,739 8,048

645 2,892

2,384 10,94 0

22% 100%

44%

What are the economic impacts? 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
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Page 554 of 946

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
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Page 555 of 946

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

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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-years181 in direct employment impacts in 2015. 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:
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.
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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
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not cause large employment changes.182

For more

information, please refer to the RIA for this proposed rule. 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 Demand Effect Cost Effect Effect Change in Full-Time Jobs per Million −3.56 2.42 2.68 Dollars of Environmental Expenditurea Standard Error 2.03 1.35 0.83 EPA estimate −45,000 to +4,700 to +200 to 32,000 for Proposed +2,500 24,000 b Rule a Expressed in 1987 dollars. See footnote 2 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. 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.
182

For alternative views in economic journals, see Henderson (1996) and Greenstone (2002).
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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 expertbased 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. TABLE 27. SUMMARY OF THE PM2.5 MONETIZED CO-BENEFITS ESTIMATES FOR THE PROPOSED TOXICS RULE IN 2016 (BILLIONS OF 2007$)a

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.
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Estimated Emission reductions (million tons per year) PM2.5 Precursors SO2
a

Monetized PM2.5 Cobenefits (3% Discount Rate) $58 to $140

Monetized PM2.5 Cobenefits (7% Discount Rate) $53 to $130

2.1

Total $58 to $140 $53 to $130 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 of

human health benefits derived from reducing PM2.5 and PM2.5 precursor emissions, we used the general approach and methodology on the laid out in Fann, et al. (2009).184 To generate the benefit-per-ton estimates, we used a model to convert emissions of PM2.5 precursors into changes
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.
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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 benefitper-ton estimates. Even though we assume that all fine

particles have equivalent health effects, the benefit-perton 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

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cohort study185

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. 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 analysis187 provides an indication of the sensitivity of our results to various assumptions. 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 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: 667-672 187 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
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185

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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. 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 Total Monetized Benefitsb Hg-related Benefitsc CO2-related Benefits PM2.5-related Cobenefitsd Total Social Costse Net Benefits $59,0 00 $4.1 to 7% Discount Rate to to $570 $130,0 00 $0.89

$140,00 $53,00 0 0 to $5.9 $0.45

$570

$59,000 to $53,000 to $140,000 $130,000 $10,900 $10,900 $48,0 to $130,00 $42,00 to $130,00 0 0 00 0 Non-monetized Visibility in Class I areas Benefits 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
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topic deemed this marginal value to be the central value. In section 6.6 of the RIA we also report he 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 F 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. met with these SERs to discuss the potential rulemaking
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We

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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.
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EPA

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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. 584 tribal leaders. Consultation letters were sent to

The letters provided information

regarding EPA’s development of NESHAP for EGUs and offered consultation. and held. Three consultation meetings were requested

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. A. Statutory and Executive Order Reviews

Executive Order 12866, Regulatory Planning and Review

and Executive Order 13563, Improving Regulation and Regulatory Review Under EO 12866 (58 FR 51,735, 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
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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-thescience 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 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 3,821,
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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
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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

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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
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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.
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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

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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 In

above the EPA’s RfD equivalent level for hair Hg.

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 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
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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
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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
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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
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incidence of AMI.

Further, both studies report

statistically significantly positive trend tests for the relationship between MeHg and AMI. The USHPS provides some The NSHDS

additional evidence of a positive association.

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 Tapajós 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 Three studies

epidemiological studies are more consistent.

(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
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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. 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 7year-old children; this association was no longer seen in the children tested at 14 years. 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 Other studies suggest A

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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 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

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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
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Page 581 of 946

controlled sufficiently for potential confounders. ) study of adults living in the Tapajós River region in Brazil (Amorim, et al., 2000) reported a direct

One

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

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Page 582 of 946

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
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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
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Page 584 of 946

(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. 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 Note

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, Further

numerous adverse effects have been identified.

reducing the presence of Hg in the environment may help to
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Page 585 of 946

alleviate the potential for adverse ecological health outcomes. A review of the literature on effects of Hg on fish188 reports results for numerous species including trout, bass (large and smallmouth), northern pike, carp, walleye, salmon, and others from 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. Mercury also affects avian species. In previous

reports189 much of the focus has been on large piscivorous
188

Crump, KL, and Trudeau, VL. Mercury-induced reproductive impairment in fish. Environmental Toxicology and Chemistry. Vol. 28, No. 5, 2009. 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-97007. 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,
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Page 586 of 946

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,

Research Triangle Park, NC., March; EPA report no. EPA452/R-05-003. Available on the Internet at  8,300 Btu/lb, and 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 §63.10042. (1) (2) EGUs designed to burn liquid oil, and EGUs designed to burn solid oil-derived fuel.

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Page 709 of 946

(c)

IGCC units combusting either gasified coal or gasified For purposes of compliance,

solid oil-derived fuel.

monitoring, recordkeeping, and reporting requirements in this rule, IGCC units are subject in the same manner as coal-fired units and solid oil-derived fuel-fired units, unless otherwise indicated. §63.9991 What emission limitations, work practice

standards, and operating limits must I meet? (a) You must meet the requirements in paragraphs (a)(1) You must meet these requirements

and (2) of this section. 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 §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

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Page 710 of 946

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 If you use a control

subpart that applies to your EGU.

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 §63.8(f). (b) As provided in §63.6(g), EPA may approve use of an

alternative to the work practice standards in this section. General Compliance Requirements §63.10000 What are my general requirements for complying

with this subpart? (a) You must be in compliance with the emission limits and These limits apply to

operating limits in this subpart. 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

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Page 711 of 946

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

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Page 712 of 946

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 §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
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Page 713 of 946

trap monitoring system for Hg, you must develop a sitespecific 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 §63.8(f). 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 §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 This

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

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Page 714 of 946

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 §63.8(d) or Appendix A to this subpart, as applicable. (5) Ongoing operation and maintenance procedures in

accordance with the general requirements of §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 §63.8(c)(7)(i) and for responding to out of control periods consistent with §§63.8(c)(7)(ii) and (c)(8) or Appendix A to this subpart, as applicable. (7) Ongoing recordkeeping and reporting procedures in

accordance with the general requirements of §63.10(c),
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Page 715 of 946

(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. §63.10001 Affirmative Defense for Exceedence of Emission

Limit During Malfunction. In response to an action to enforce the standards set forth in paragraph §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:
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(1) (i)

The excess emissions: 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

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Page 717 of 946

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
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Page 718 of 946

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 §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
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Page 719 of 946

exceedances. Testing, Fuel Analyses, and Initial Compliance Requirements §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 §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
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Page 720 of 946

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 §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;
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Page 721 of 946

(ii)

The performance test was conducted in accordance with

all requirements contained in §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. (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 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
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Page 722 of 946

requirement is to conduct a fuel analysis for each type of fuel burned in your EGU according to §63.10008 and Table 6 to this subpart and establish operating limits according to §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 §63.10008 and Table 6 to this subpart and establish operating limits according to §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 §63.10008 and Table 6 of this subpart; and (iii) You certify, and have and keep documentation

demonstrating, that the EGU configuration, control devices,
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Page 723 of 946

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 §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 §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 §63.10008 and Table 6 to this subpart. (d) (1) CMS Requirements. 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
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Page 724 of 946

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
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Page 725 of 946

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
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Page 726 of 946

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 §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 §63.9984 and according to the applicable provisions in §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 [INSERT DATE OF
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Page 727 of 946

PUBLICATION OF THIS PROPOSED RULE IN THE FEDERAL REGISTER] 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 §63.7(a)(2)(ix). (i) If your new or reconstructed affected source commenced

construction or reconstruction between [INSERT DATE OF PUBLICATION OF THIS PROPOSED RULE IN THE FEDERAL REGISTER], 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
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Page 728 of 946

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. (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 §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 When qualifying for LEE status for Hg

status for Hg.

emissions less than or equal to 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 For all pollutants or surrogates

unit qualifies as a LEE.

except for Hg, conduct the initial performance tests as described in §63.10007 but note that the required minimum
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Page 729 of 946

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 §63.10010(k)(3). Calculate the

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average Hg concentration, in µg/m3, for the 28 to 30 day performance test, as the arithmetic average of all sorbent trap results. Calculate the average CO2 or O2 concentration Use the average Hg concentration and

for the test period.

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. (l) Startup and Shutdown default values for calculations.

For the purposes of this rule and only during periods of startup or shutdown, use a default diluents 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.
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§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 §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 §63.10007 at least every 5 years.
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(c)

For affected units meeting the LEE requirements of

§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 §63.10007 and conduct fuel sampling and analysis according to Table 6 and §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. (i) If this should occur:

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. (ii) 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
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period and under the same process (e.g., fuel) and control device operating conditions according to Table 5 and §63.10007 at least every year and you must conduct non-Hg HAP metals emissions testing according to Table 5 and §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 nonHg HAP metals emissions according to Table 5 and §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 §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 §63.10007 at least every month. (h) For solid oil-derived fuel- and coal-fired EGUs

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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 §63.10007 at least every year and you must conduct SO2 emissions testing according to §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 §63.10007 at least every year and you must conduct HCl emissions testing according to Table 5 and §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 §63.10007 at least every
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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 §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 §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 §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
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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 §63.10009, you must continue to conduct performance stack tests at the appropriate frequency given in section (c)
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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 §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
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according to §63.10007.

Each performance tune-up specified

in §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 §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 §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 §63.10011 and Table 7 to this subpart, as applicable. The reports for all

subsequent performance tests must include all applicable information required in §63.10031.
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§63.10007

What methods and other procedures must I use for

the performance tests? (a) You must conduct all performance tests according to You must also develop a site-

§63.7(c), (d), (f), and (h).

specific test plan according to the requirements in §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
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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 §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 §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
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Page 741 of 946

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 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. §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
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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
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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

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material (fines and coarse) in the full cross-section. must transfer the sample to a clean plastic bag. (ii)

You

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 You must insert a clean flat square

a depth of 18 inches.

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

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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) (7) You must grind the sample in a mill. 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. §63.10009 May I use emission averaging to comply with this

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Page 746 of 946

subpart? (a) As an alternative to meeting the requirements of

§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
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Page 747 of 946

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] 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 or

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 §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
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Page 748 of 946

limits in Table 2 to this subpart.

Ave Weighted Emissions

Er

Hm

Hm

Eq. 1

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 §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. Ave Weighted Emissions Er Sm Cfi Sm Cfi Eq. 2

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Page 749 of 946

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 §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 §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.

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Ave Weighted Emissions

Er

Hb

Hb

Eq. 3

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 §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. Ave Weighted Emissions Er Sa Cfi Sa Cfi Eq. 4

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
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Page 751 of 946

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 §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 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. Eavg ERi 12 Eq. 5

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)).
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(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). (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

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Page 753 of 946

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 §63.10007; (v) The operating parameters to be monitored for each

control system or device consistent with §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 §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;
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Page 754 of 946

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.
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(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 §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
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Page 756 of 946

determined by the use of equation 6.

En

ELi

Hi

Hi

Eq. 6

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 If affected

specified in §63.10007 in the common stack.

units from nonaffected units vent to the common stack, (A) the units from nonaffected units must be shut down or vented to a different stack during the performance test or (B) each affected and each nonaffected unit must meet the most stringent emissions limit; and (3) Meet the applicable operating limit specified in

§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
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Page 757 of 946

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. §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 with the applicable performance specification or Appendix A to this subpart. (2) Unit Utilizing Common Stack with Other Affected

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Page 758 of 946

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
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Page 759 of 946

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

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Page 760 of 946

§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) below. (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 §63.10000(d). (2) Conduct a performance evaluation of the CEMS according

to the requirements in §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 §63.8(g)(2) and

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Page 761 of 946

(4). (5) Consistent with §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 a 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 §63.9984. outlet of the EGU. (1) Install, operate, and maintain the CEMS according to The HCl shall be monitored at the

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 sitespecific monitoring plan developed according to §63.10000(d). (2) Conduct a performance evaluation of the CEMS according

to the requirements in §63.8 and according to PS 15 of 40
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Page 762 of 946

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) (4). (5) Consistent with §63.10020, calculate and record a 30 Reduce the CEMS data as specified in §63.8(g)(2) and

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 a 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 §63.9984. outlet of the EGU. (1) Install, operate, and maintain the CEMS according to The HF shall be monitored at the

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
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Page 763 of 946

of 40 CFR part 60, Appendix F; and according to the sitespecific monitoring plan developed according to §63.10000(d). (2) Conduct a performance evaluation of the CEMS according

to the requirements in §63.8 and according to PS 15 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) (4). (5) Consistent with §63.10020, calculate and record a 30 Reduce the CEMS data as specified in §63.8(g)(2) and

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 a 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 §63.9984. The SO2 shall be monitored at the

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Page 764 of 946

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 §63.10000(d). (2) Conduct a performance evaluation of the CEMS according

to the requirements in §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 §63.8(g)(2) and

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Page 765 of 946

(4). (5) Consistent with §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
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Page 766 of 946

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 §63.9984. outlet of the EGU. (1) Install, operate, and maintain according to the The PM shall be monitored at 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 sitespecific monitoring plan developed according to §63.10000(d). (2) Conduct a performance evaluation of the CEMS according

to the requirements in §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

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Page 767 of 946

one cycle of operation (sampling, analyzing, and data recording) for each successive 15-minute period. (4) (4). (5) Consistent with §63.10020, calculate and record a 30 Reduce the CEMS data as specified in §63.8(g)(2) and

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 §63.9984. (1) Install, operate, and maintain each CPMS according to

the procedures in your approved site-specific monitoring plan developed in accordance with §63.10000(d) of this subpart and the design criteria and quality assurance and quality control procedures specified in paragraphs (h)(1)
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Page 768 of 946

through (3).

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 §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 (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.
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Page 769 of 946

(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 (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
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Page 770 of 946

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 (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

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Page 771 of 946

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 (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 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 (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)
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Page 772 of 946

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-98015 (incorporated by reference, see §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.
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Page 773 of 946

§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 §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 §63.10007, Table 7 to this subpart, and paragraph (c)(6) of this section, as applicable. You must also conduct fuel analyses according

to §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.
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Page 774 of 946

(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.

Clinput

Ci

Qi

Eq. 7

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 §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
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Page 775 of 946

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. Mercuryinput HGi Qi Eq. 8

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 §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

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Page 776 of 946

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.

HAP metalinput

HAP metali

Qi

Eq. 9

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 §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 non-Hg HAP metal content. If you do not burn multiple fuel types during the
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Page 777 of 946

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. Flinput ∑ Fi Qi Eq. 10

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
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Page 778 of 946

type, i, analyzed according to §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 §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 §63.10042, as
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Page 779 of 946

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 §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 §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
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Page 780 of 946

be installed according to the requirements in §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 §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. P90 mean SD t Eq. 11

Where: P90 = 90th percentile confidence level pollutant concentration, in lb/MMBtu (lb/TBtu for Hg).
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Page 781 of 946

mean = Arithmetic average of the fuel pollutant concentration in the fuel samples analyzed according to §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 §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.

HCl

Ci90

Qi

1.028

Eq. 12

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
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Page 782 of 946

your EGU using Equation 13 of this section must not exceed the applicable emission limit for Hg. Mercury HGi90 Qi Eq. 13

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 section must not exceed the applicable emissions limit for non-Hg HAP metals.

HAPmetals

HAPmetalsi90

Qi

Eq. 14

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
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Page 783 of 946

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.

HF

Fi90

Qi

1.053

Eq. 15

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
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Page 784 of 946

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 results. 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 §63.10030(e). (f) If you are a LEE, the results of your initial

performance test demonstrate your initial compliance. Continuous Compliance Requirements §63.10020 How do I monitor and collect data to demonstrate

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Page 785 of 946

continuous compliance? (a) You must monitor and collect data according to this

section and the site-specific monitoring plan required by §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 §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
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Page 786 of 946

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. §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.
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(1)

Following the date on which the initial performance

test is completed or is required to be completed under §§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 §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
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Page 788 of 946

through performance stack testing). (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 §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 §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 §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
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Page 789 of 946

§63.10011.

If the results of recalculating the maximum

chlorine input using Equation 7 of §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 §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 §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 §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
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Page 790 of 946

§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 §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 §63.10011. If the results of recalculating the maximum Hg

input using Equation 8 of §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 §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 §63.10011(b).
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(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 §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 §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 §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,
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Page 792 of 946

you must recalculate the maximum HAP metals input using Equation 9 of §63.10011. If the results of recalculating

the maximum Hg input using Equation 9 of §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 §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 §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
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Page 793 of 946

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 6month 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

§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

§§63.10010(a) and 63.10020. (ii) Keep records of oxygen levels according to

§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
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Page 794 of 946

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 §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 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 §63.2 and as required in this subpart, you must submit
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Page 795 of 946

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 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 §63.13. If acceptable to both the Administrator and the owner or operator of a source,
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Page 796 of 946

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 §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
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this section. (i) The owner or operator shall conduct a performance

evaluation of the CEMS according to the applicable requirements of §60.13 of 40 CFR, Performance Specification 2 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

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Page 798 of 946

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

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Page 799 of 946

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
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Page 800 of 946

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 §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
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Page 801 of 946

accuracy test audit data electronically into EPA’s Central Data Exchange by using the Electronic 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 §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 §63.10031.
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Page 802 of 946

(c)

Consistent with §63.10010, §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. §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 §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
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Page 803 of 946

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.
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Page 804 of 946

(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 §63.10030 (a) What notifications must I submit and when?

You must submit all of the notifications in §§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 §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 §63.9(b)(4) and (b)(5), if you startup

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Page 805 of 946

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 §63.10011(a), you must submit a Notification of Compliance Status according to §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 §63.10(d)(2). The Notification of Compliance Status report

must contain all the information specified in paragraphs (e)(1) through (6), as applicable.
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Page 806 of 946

(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.
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Page 807 of 946

(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

§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

§63.10021(a)(16)(i) through (vi).” §63.10031 (a) What reports must I submit and when?

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 §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.
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(1)

The first compliance report must cover the period

beginning on the compliance date that is specified for your affected source in §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 §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 §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,
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Page 809 of 946

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) (2) Company name and address. 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
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Page 810 of 946

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 §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 §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 Or, if you did burn a new type of fuel, you

types of fuel.

must submit the calculation of chlorine input, using Equation 7 of §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 §63.10011 that demonstrates that
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Page 811 of 946

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 §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 §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 §63.10011 or the maximum Hg input operating limit using Equation 8 of §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

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Page 812 of 946

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 §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 §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.
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(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 §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,

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Page 814 of 946

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 §63.8(c)(8). (4) The date and time that each deviation started and

stopped, and whether each deviation occurred during 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.
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(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,
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Page 816 of 946

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

§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

§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 §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
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Page 817 of 946

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 §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
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Page 818 of 946

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 §63.10000(b), including actions taken to correct a malfunction. §63.10032 (a) What records must I keep?

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 §63.10(b)(2)(xiv). (2) Records of performance stack tests, fuel analyses, or

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Page 819 of 946

other compliance demonstrations and performance evaluations, as required in §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) (2) Records described in §63.10(b)(2) (vi) through (xi). Previous (i.e., superseded) versions of the

performance evaluation plan as required in §63.8(d)(3). (3) Request for alternatives to relative accuracy test for

CEMS as required in §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
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Page 820 of 946

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 §63.10011, that were done to demonstrate continuous compliance with the HCl emission limit, for sources that demonstrate compliance through performance
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Page 821 of 946

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 §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 §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 §63.10011, that were done to demonstrate compliance with the Hg emission limit. Supporting documentation should include results of

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Page 822 of 946

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 §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

§63.10009, you must additionally keep a copy of the emission averaging implementation plan required in §63.10009(g), all calculations required under §63.10009, including daily records of heat input or steam generation, as applicable, and monitoring records consistent with
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Page 823 of 946

§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 §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. §63.10033 records? (a) Your records must be in a form suitable and readily In what form and how long must I keep my

available for expeditious review, according to §63.10(b)(1). (b) As specified in §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

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Page 824 of 946

after the date of each occurrence, measurement, maintenance, corrective action, report, or record, according to §63.10(b)(1). You can keep the records off

site for the remaining 3 years. Other Requirements and Information §63.10040 me? Table 10 to this subpart shows which parts of the General Provisions in §§63.1 through 63.15 apply to you. §63.10041 (a) Who implements and enforces this subpart? What parts of the General Provisions apply to

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
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Page 825 of 946

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 §63.9991(a) and (b) under §63.6(g). (2) Approval of major change to test methods in Table 5 to

this subpart under §63.7(e)(2)(ii) and (f) and as defined in §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 §63.2), and approval of alternative analytical methods requested under §63.10008(b)(2). (3) Approval of major change to monitoring under §63.8(f)

and as defined in §63.90, and approval of alternative operating parameters under §§63.9991(a)(2) and 63.10009(g)(2). (4) Approval of major change to recordkeeping and

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Page 826 of 946

reporting under §63.10(e) and as defined in §63.90. §63.10042 What definitions apply to this subpart?

Terms used in this subpart are defined in the Clean Air Act (CAA), in §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
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Page 827 of 946

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)∈1 (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– 9911 (incorporated by reference, 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
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Page 828 of 946

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 fuelfired 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

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Page 829 of 946

the date the unit first produces electricity and during any calendar year after which the unit first produces electricity: (i) (A) For a topping-cycle cogeneration unit, 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
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Page 830 of 946

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 §63.14(b)(40)). Dry flue gas desulfurization technology, or dry FGD, or spray dryer absorber (SDA), or spray dryer, or dry
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Page 831 of 946

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
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Page 832 of 946

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
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Page 833 of 946

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 Clearly states that

a published VCS or EPA method 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
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Page 834 of 946

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 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 seam 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.
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Page 835 of 946

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

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Page 836 of 946

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. 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 Blast furnace

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
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Page 837 of 946

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 combinedcycle 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
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Page 838 of 946

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)∈1 (incorporated by reference, see §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
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Page 839 of 946

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 §63.14(b)(41)). Net-electric output means the gross electric sales to
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Page 840 of 946

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
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Page 841 of 946

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 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 §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
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Page 842 of 946

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
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Page 843 of 946

combustion, and an ash discharge system. general types of stokers:

There are two

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)∈1 (incorporated by reference, see §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 heightto-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
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Page 844 of 946

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

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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).
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Tables to Subpart UUUUU of Part 63 Table 1 to Subpart UUUUU of Part 63 — Emission Limits for New or Reconstructed EGUs As stated in §63.9991, you must comply with the following applicable emission limits:
If your EGU is in this subcategory ... You must meet the For the following emission following pollutants ... limits and work practice standards ... Using these requirements, as appropriate, (e.g., specified sampling volume or test run duration) with the test methods in Table 5…
Collect a minimum of 4 dscm per run Collect a minimum of 4 dscm per run Collect a minimum of 4 dscm per run

1. Coal-fired unit designed for coal > 8,300 Btu/lb.

a. Total particulate matter (PM) OR Total non-Hg HAP metals OR Individual HAP metals: Antimony (Sb) Arsenic (As) Beryllium (Be) Cadmium (Cd) Chromium (Cr) Cobalt (Co) Lead (Pb) Manganese (Mn) Nickel (Ni) Selenium (Se) b. Hydrogen chloride (HCl)

0.050 lb per MWh.

OR 0.000040 lb per MWh.

OR

0.000080 lb/GWh 0.00020 lb/GWh 0.000030 lb/GWh 0.00040 lb/GWh 0.060 lb/GWh 0.00080 lb/GWh 0.00090 lb/GWh 0.0040 lb/GWh 0.0040 lb/GWh 0.030 lb/GWh 0.30 lb per GWh.

For Method 26A, collect a minimum of 4 dscm per

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Page 847 of 946 Run OR Sulfur dioxide (SO2)204 c. Mercury (Hg) 0.40 lb per MWh. 0.000010 lb per GWh. SO2 CEMS Hg CEMS or Sorbent trap monitoring system Collect a minimum of 4 dscm per run Collect a minimum of 4 dscm per run Collect a minimum of 4 dscm per run

2. Coal-fired unit designed for coal < 8,300 Btu/lb

a. Total particulate matter (PM) OR Total non-Hg HAP metals OR Individual HAP metals: Antimony (Sb) Arsenic (As) Beryllium (Be) Cadmium (Cd) Chromium (Cr) Cobalt (Co) Lead (Pb) Manganese (Mn) Nickel (Ni) Selenium (Se) b. Hydrogen chloride (HCl)

0.050 lb per MWh.

OR 0.000040 lb per MWh.

OR

0.000080 lb/GWh 0.00020 lb/GWh 0.000030 lb/GWh 0.00040 lb/GWh 0.060 lb/GWh 0.00080 lb/GWh 0.00090 lb/GWh 0.0040 lb/GWh 0.0040 lb/GWh 0.030 lb/GWh 0.30 lb per GWh.

For Method 26A, collect a minimum of 4 dscm per Run SO2 CEMS Hg CEMS or Sorbent trap

OR Sulfur dioxide (SO2)205 c. Mercury (Hg)
204

0.40 lb per MWh. 0.040 lb per GWh.

The alternate sulfur dioxide limit may not be used if your EGU does not have some form of flue gas desulfurization system installed. 205 The alternate sulfur dioxide limit may not be used if your EGU does not have some form of flue gas desulfurization system installed.
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Page 848 of 946 monitoring system Collect a minimum of 4 dscm per run Collect a minimum of 4 dscm per run Collect a minimum of 4 dscm per run

3.

IGCC unit

a. Particulate matter (PM) OR Total non-Hg HAP metals OR Individual HAP metals: Antimony (Sb) Arsenic (As) Beryllium (Be) Cadmium (Cd) Chromium (Cr) Cobalt (Co) Lead (Pb) Manganese (Mn) Nickel (Ni) Selenium (Se) b. Hydrogen chloride (HCl)

0.050 lb per MWh.

OR 0.000040 lb per MWh.

OR

0.000080 lb/GWh 0.00020 lb/GWh 0.000030 lb/GWh 0.00040 lb/GWh 0.060 lb/GWh 0.00080 lb/GWh 0.00090 lb/GWh 0.0040 lb/GWh 0.0040 lb/GWh 0.030 lb/GWh 0.30 lb per GWh.

For Method 26A, collect a minimum of 4 dscm per Run SO2 CEMS Hg CEMS or Sorbent trap monitoring system Collect a minimum of 4 dscm per run Collect a minimum of 4 dscm per run

OR Sulfur dioxide (SO2)206 c. Mercury (Hg) 0.40 lb per MWh. 0.000010 lb per GWh.

4. Liquid oilfired unit

a. Total HAP metals OR Individual HAP metals: Antimony (Sb) Arsenic (As)

0.00040 lb/MWh.

OR

0.0020 lb/GWh 0.0020 lb/GWh

206

The alternate sulfur dioxide limit may not be used if your EGU does not have some form of flue gas desulfurization system installed.
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Page 849 of 946 Beryllium (Be) Cadmium (Cd) Chromium (Cr) Cobalt (Co) Lead (Pb) Manganese (Mn) Nickel (Ni) Selenium (Se) Mercury (Hg) 0.00070 lb/GWh 0.00040 lb/GWh 0.020 lb/GWh 0.0060 lb/GWh 0.0060 lb/GWh 0.030 lb/GWh 0.040 lb/GWh 0.0040 lb/GWh 0.00010 lb/GWh For Method 30B sample volume determination (8.2.4), the estimated Hg concentration should nominally be < ½ the standard For Method 26A, collect a minimum of 4 dscm per Run For Method 26A, collect a minimum of 4 dscm per Run Collect a minimum of 4 dscm per run Collect a minimum of 4 dscm per run Collect a minimum of 4 dscm per run

b. Hydrogen chloride (HCl)

0.00050 lb/MWh

c. Hydrogen fluoride (HF)

0.00050 lb/MWh

a. Particulate 0.050 lb/MWh 5. Solid oilderived fuel-fired matter (PM) unit OR OR Total non-Hg HAP metals OR Individual HAP metals: Antimony (Sb) Arsenic (As) Beryllium (Be) Cadmium (Cd) Chromium (Cr) Cobalt (Co) Lead (Pb) Manganese (Mn) Nickel (Ni) Selenium (Se) 0.00020 lb/MWh

OR

0.00090 lb/GWh 0.0020 lb/GWh 0.000080 lb/GWh 0.0070 lb/GWh 0.0060 lb/GWh 0.0020 lb/GWh 0.020 lb/GWh 0.0070 lb/GWh 0.0070 lb/GWh 0.00090 lb/GWh

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Page 850 of 946 b. Hydrogen chloride (HCl) 0.00030 lb/MWh For Method 26A, collect a minimum of 4 dscm per run SO2 CEMS Hg CEMS or Sorbent trap monitoring system

OR Sulfur dioxide (SO2)207 c. Mercury (Hg) 0.40 lb/MWh 0.0020 lb/GWh

Table 2 to Subpart UUUUU of Part 63 — Emission Limits for Existing EGUs As stated in §63.9991, you must comply with the following applicable emission limits:208
If your EGU is in this subcategory ... You must meet the For the following following emission pollutants ... limits and work practice standards ... Using these requirements, as appropriate (e.g., specified sampling volume or test run duration) with the test methods in Table 5…
Collect a minimum of 2 dscm per run Collect a minimum of 4

1. Coal-fired unit designed for coal > 8,300 Btu/lb.

a. Total particulate matter (PM) OR Total non-Hg HAP metals

0.030 lb/MMBtu or 0.30 lb/MWh OR 0.000040 lb/MMBtu 0.00040 lb/MWh

The alternate sulfur dioxide limit may not be used if your EGU does not have some form of flue gas desulfurization system installed. 208 For LEE emissions testing for total PM, total HAP metals, individual HAP metals, HCl, and HF, the required minimum sampling volume must be increased nominally by a factor of two.
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207

Page 851 of 946 dscm per run OR Individual HAP metals: Antimony (Sb) Arsenic (As) Beryllium (Be) Cadmium (Cd) Chromium (Cr) Cobalt (Co) Lead (Pb) Manganese (Mn) Nickel (Ni) Selenium (Se) b. Hydrogen chloride (HCl) OR Collect a minimum of 4 dscm per run

0.60 lb/TBtu or 0.0060 lb/GWh 2.0 lb/TBtu or 0.020 lb/GWh 0.20 lb/TBtu or 0.0020 lb/GWh 0.30 lb/TBtu or 0.0030 lb/GWh 3.0 lb/TBtu or 0.030 lb/GWh 0.80 lb/TBtu or 0.0080 lb/GWh 2.0 lb/TBtu or 0.020 lb/GWh 5.0 lb/TBtu or 0.050 lb/GWh 4.0 lb/TBtu or 0.040 lb/GWh 6.0 lb/TBtu or 0.060 lb/GWh

0.0020 lb per MMBtu For Method 26A, collect a or minimum of 0.020 lb per MWh 0.75 dscm per run; for Method 26, collect a minimum of 60 liters per run 0.20 lb per MMBtu or 2.0 lb per MWh 1.0 lb/TBtu or 0.008 lb/GWh

OR Sulfur dioxide (SO2)209 c. Mercury (Hg)

SO2 CEMS LEE Testing for 28-30 days with 10 days maximum per run or Hg CEMS or

209

The alternate sulfur dioxide limit may not be used if your EGU does not have some form of flue gas desulfurization system installed.
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Page 852 of 946

Sorbent trap monitoring system
2. Coal-fired unit designed for coal < 8,300 Btu/lb a. Total particulate matter (PM) OR Total non-Hg HAP metals OR Individual HAP metals: Antimony (Sb) Arsenic (As) Beryllium (Be) Cadmium (Cd) Chromium (Cr) Cobalt (Co) Lead (Pb) Manganese (Mn) Nickel (Ni) Selenium (Se) b. Hydrogen chloride (HCl) 0.030 lb/MMBtu or 0.30 lb/MWh OR 0.000040 lb/MMBtu 0.00040 lb/MWh OR Collect a minimum of 4 dscm per run Collect a minimum of 4 dscm per run Collect a minimum of 4 dscm per run

0.60 lb/TBtu or 0.0060 lb/GWh 2.0 lb/TBtu or 0.020 lb/GWh 0.20 lb/TBtu or 0.0020 lb/GWh 0.30 lb/TBtu or 0.0030 lb/GWh 3.0 lb/TBtu or 0.030 lb/GWh 0.80 lb/TBtu or 0.0080 lb/GWh 2.0 lb/TBtu or 0.020 lb/GWh 5.0 lb/TBtu or 0.050 lb/GWh 4.0 lb/TBtu or 0.040 lb/GWh 6.0 lb/TBtu or 0.060 lb/GWh

0.0020 lb per MMBtu For Method 26A, collect a or minimum of 0.020 lb per MWh 0.75 dscm per run; for Method 26, collect a minimum of 60 liters per run 0.20 lb per MMBtu or SO2 CEMS

OR Sulfur dioxide (SO2)210
210

The alternate sulfur dioxide limit may not be used if
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Page 853 of 946 2.0 lb per MWh 4.0 lb/TBtu or 0.040 lb/GWh

c. Mercury (Hg)

3.

IGCC unit

a. Total particulate matter (PM) OR Total non-Hg HAP metals OR Individual HAP metals: Antimony (Sb) Arsenic (As) Beryllium (Be) Cadmium (Cd) Chromium (Cr) Cobalt (Co) Lead (Pb) Manganese (Mn) Nickel (Ni) Selenium (Se) b. Hydrogen chloride (HCl)

0.050 lb/MMBtu or 0.30 lb/MWh OR 5.0 lb/TBtu or 0.050 lb/GWh OR

LEE Testing for 28-30 days with 10 days maximum per run or Hg CEMS or Sorbent trap monitoring system Collect a minimum of 4 dscm per run Collect a minimum of 4 dscm per run Collect a minimum of 4 dscm per run

0.40 lb/TBtu or 0.0040 lb/GWh 2.0 lb/TBtu or 0.020 lb/GWh 0.030 lb/TBtu or 0.0030 lb/GWh 0.20 lb/TBtu or 0.0020 lb/GWh 3.0 lb/TBtu or 0.020 lb/GWh 0.60 lb/TBtu or 0.0040 lb/GWh 29.0 lb/MMBtu or 0.30 lb/MWh 3.0 lb/TBtu or 0.020 lb/GWh 5.0 lb/TBtu or 0.050 lb/GWh 22.0 lb/TBtu or 0.20 lb/GWh 0.00050 lb/MMBtu or For Method 0.0030 lb/MWh 26A, collect a minimum of 4 dscm per run

your EGU does not have some form of flue gas desulfurization system installed.
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Page 854 of 946 c. Mercury (Hg) 3.0 lb/TBtu or 0.020 lb/GWh LEE Testing for 28-30 days with 10 days maximum per run or Hg CEMS or Sorbent trap monitoring system Collect a minimum of 4 dscm per run Collect a minimum of 4 dscm per run

4. Liquid oil-fired a. Total HAP unit metals OR Individual HAP metals: Antimony (Sb) Arsenic (As) Beryllium (Be) Cadmium (Cd) Chromium (Cr) Cobalt (Co) Lead (Pb) Manganese (Mn) Nickel (Ni) Selenium (Se) Mercury (Hg)

0.000030 lb/MMBtu or 0.00030 lb/MWh OR

0.20 lb/TBtu or 0.0030 lb/GWh 0.60 lb/TBtu or 0.0070 lb/GWh 0.060 lb/TBtu or 0.00070 lb/GWh 0.10 lb/TBtu or 0.0020 lb/GWh 2.0 lb/TBtu or 0.020 lb/GWh 3.0 lb/TBtu or 0.020 lb/GWh 2.0 lb/TBtu or 0.030 lb/GWh 5.0 lb/TBtu or 0.060 lb/GWh 8.0 lb/TBtu or 0.080 lb/GWh 2.0 lb/TBtu or 0.020 lb/GWh 0.050 lb/TBtu or 0.00070 lb/GWh

For Method 29 collect a minimum of 4 dscm per run or for Method 30B sample volume determination (8.2.4), the estimated Hg concentration should nominally be < ½ the standard

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Page 855 of 946 b. Hydrogen chloride (HCl) 0.00030 lb/MMBtu or For Method 0.0030 lb/MWh 26A, collect a minimum of 4 dscm per run 0.00020 lb/MMBtu or For Method 0.0020 lb/MWh 26A, collect a minimum of 4 dscm per run 0.20 lb/MMBtu or Collect a 2.0 lb/MWh minimum of 2 dscm per run OR 0.000050 lb/MMBtu or 0.0010 lb/MWh OR Collect a minimum of 4 dscm per run Collect a minimum of 2 dscm per run

c. Hydrogen fluoride (HF)

5. Solid oilderived fuel-fired unit

a. Total particulate matter (PM) OR Total non-Hg HAP metals OR Individual HAP metals Antimony (Sb) Arsenic (As) Beryllium (Be) Cadmium (Cd) Chromium (Cr) Cobalt (Co) Lead (Pb) Manganese (Mn) Nickel (Ni) Selenium (Se) b. Hydrogen chloride (HCl)

0.40 lb/TBtu or 0.0070 lb/GWh 0.40 lb/TBtu or 0.0040 lb/GWh 0.070 lb/TBtu or 0.00070 lb/GWh 0.40 lb/TBtu or 0.0040 lb/GWh 2.0 lb/TBtu or 0.020 lb/GWh 2.0 lb/TBtu or 0.020 lb/GWh 11.0 lb/TBtu or 0.020 lb/GWh 3.0 lb/TBtu or 0.040 lb/GWh 9.0 lb/TBtu or 0.090 lb/GWh 2.0 lb/TBtu 0.020 lb/GWh 0.0050 lb/MMBtu or 0.050 lb/GWh

For Method 26A, collect a minimum of 1 dscm per run; for Method 26, collect a minimum of 60 liters per run

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Page 856 of 946 OR Sulfur dioxide (SO2)195 c. Mercury (Hg)

0.40 lb/MMBtu or 5.0 lb/MWh 0.20 lb/TBtu or 0.0020 lb/GWh

SO2 CEMS LEE Testing for 28-30 days with 10 days maximum per run or Hg CEMS or Sorbent trap monitoring system

Table 3 to Subpart UUUUU of Part 63 — Work Practice Standards As stated in §§63.9991, you must comply with the following applicable work practice standards:
If your EGU is...
1. 2. An existing EGU A new EGU

You must meet the following...
Conduct a performance test of the EGU annually as specified in §63.10005. Conduct a performance test of the EGU annually as specified in §63.10005.

Table 4 to Subpart UUUUU of Part 63 — Operating Limits for EGUs As stated in §63.9991, you must comply with the applicable operating limits:
You must meet these operating limits ... If you demonstrate compliance using ...
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.

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Page 857 of 946 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 a. Install and operate a bag leak detection system control according to §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 a. This option is only for EGUs that operate additional wet control systems. Maintain the precipitator secondary power input of the electrostatic control 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, Maintain the sorbent or carbon injection rate at or above the lowest 1-hour average sorbent flow rate DSI, or carbon injection control 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 §63.10011(d)(3),(4) and/or (5) is less than the applicable emission limits. 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. 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.

7. Performance testing

8.

PM CEMS

Table 5 to Subpart UUUUU of Part 63 — Performance Stack Testing Requirements As stated in §63.10007, you must comply with the following requirements for performance testing for existing, new or reconstructed affected sources:211
211

For emissions calculations involving periods of startup
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Page 858 of 946

To conduct a performance test for the following pollutant ...
1. Particulate matter (PM)

Using... You must ...

Using ...212

Emissions a. Select sampling ports Method 1 at 40 Testing CFR part 60, location and the number Appendix A-1 of of traverse points. this chapter. b. Determine velocity and volumetric flow-rate of the stack gas. Method 2, 2F, or 2G at 40 CFR part 60, Appendix A-1 or A-2 to part 60 of this chapter. Method 3A or 3B at 40 CFR part 60, Appendix A-2 to part 60 of this chapter, or ANSI/ASME PTC 19.10-1981. Method 4 at 40 CFR part 60, Appendix A-3 of this chapter. Method 202 at 40 CFR part 51, Appendix M of this chapter for condensable PM emissions from units and Method 5 (positive pressure fabric filters must use Method 5D) at 40 CFR part 60, Appendix A-3 or A-6 of this chapter for

c. Determine oxygen and carbon dioxide concentrations of the stack gas

d. Measure the moisture content of the stack gas

e. . Measure the PM emissions concentrations and determine the filterable and condensable fractions, as well as total PM.

or shutdown, use procedures in §63.10005(l). 212 All ASTM, ANSI, an ASME methods are incorporated by reference.
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Page 859 of 946 filterable PM emissions. Note that the Method 5 front half temperature shall be 320°F ± 25°F. f. Convert emissions concentration to lb per MMBtu emissions rates or lb/MWh emissions rates. Method 19 Ffactor methodology at 40 CFR part 60, Appendix A-7 of this chapter, or calculate using mass emissions rate and electrical output data.

Emissions a. Select sampling ports Method 1 at 40 2. Total or CFR part 60, individual non-Hg Testing location and the number Appendix A-1 of HAP metals of traverse points. this chapter. b. Determine velocity and volumetric flow-rate of the stack gas. Method 2, 2F, or 2G at 40 CFR part 60, Appendix A-1 or A-2 to part 60 of this chapter. Method 3A or 3B at 40 CFR part 60, Appendix A-2 to part 60 of this chapter, or ANSI/ASME PTC 19.10-1981.

c. Determine oxygen and carbon dioxide concentrations of the stack gas.

d. Measure the moisture Method 4 at 40 content of the stack gas. CFR part 60, Appendix A-3 of this chapter. e. Measure the HAP metals emissions concentrations and determine each individual HAP metals emissions concentration, as well as the total filterable HAP metals emissions Method 29 at 40 CFR part 60, Appendix A-8 of this chapter. Determine total filterable HAP metals according to section

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Page 860 of 946 concentration and total HAP metals emissions concentration. f. Convert emissions concentrations (individual HAP metals, total filterable HAP metals, and total HAP metals) to lb per MMBtu or lb per MWh emissions rates. 8.3.1.1 prior to beginning metals analyses. Method 19 Ffactor methodology at 40 CFR part 60, Appendix A-7 of this chapter, or calculate using mass emissions rate and electrical output data.

3. Hydrogen chloride (HCl) and hydrogen fluoride (HF)

Emissions a. Select sampling ports Method 1 at 40 Testing location and the number CFR part 60, Appendix A-1 of of traverse points. this chapter. b. Determine velocity and volumetric flow-rate of the stack gas. c. Determine oxygen and carbon dioxide concentrations of the stack gas. Method 2, 2F, or 2G at 40 CFR part 60, Appendix A-2 of this chapter. Method 3A or 3B at 40 CFR part 60, Appendix A2of this chapter, or ANSI/ASME PTC 19.10-1981.

d. Measure the moisture Method 4 at 40 content of the stack gas. CFR part 60, Appendix A-3 of this chapter. e. Measure the HCl and HF emissions concentrations. Method 26 if there are no entrained water 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.

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Page 861 of 946 f. Convert emissions concentration to lb per MMBtu or lb per MWh emissions rates. Method 19 Ffactor methodology at 40 CFR part 60, Appendix A-7 of this chapter, or calculate using mass emissions rate and electrical output data.

OR

OR

HCl and/or a. Install, operate, and PS 15 at 40 CFR HF CEMS 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 maintain the diluents gas, flow rate, and/or moisture monitoring systems c. Convert hourly emissions concentrations to 30 boiler operating day rolling average lb per MMBtu emissions rates or lb/MWh emissions rates. Section 4.1.3 and 5.3 of Appendix A of this subpart.

Method 19 Ffactor methodology at 40 CFR part 60, Appendix A-7 of this chapter, or calculate using mass emissions rate and electrical output data.

4.

Mercury (Hg)

Emissions a. Select sampling ports Method 1 at 40 Testing location and the number CFR part 60, of traverse points. Appendix A-1 of this chapter. b. Determine velocity and volumetric flow-rate of the stack gas. Method 2, 2F, or 2G at 40 CFR part 60, Appendix A-1 or A-2 of this chapter.

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Page 862 of 946 c. Determine oxygen and carbon dioxide concentrations of the stack gas. Method 3A or 3B at 40 CFR part 60, Appendix A-1 of this chapter, or ANSI/ASME PTC 19.10-1981.

d. Measure the moisture Method 4 at 40 content of the stack gas. CFR part 60, Appendix A-3 of this chapter. e. Measure the Hg emission concentration. Method 29 or 30B at 40 CFR part 60, Appendix A-8 of this chapter or ASTM Method D6784–02 (2008) as specified. Section 6 of Appendix A of this subpart.

f. Convert emissions concentration to lb per TBtu emissions rates. OR Hg CEMS OR

a. Install, operate, and Sections 3.2.1 maintain the CEMS and 5.1 of Appendix A of this subpart. b. Install, operate, and maintain the diluents gas, flow rate, and/or moisture monitoring systems Section 4.1.3 and 5.3 of Appendix A of this subpart.

Section 6 of c. Convert hourly emissions concentrations Appendix A of this subpart. to 30 boiler operating day rolling average lb per MMBtu emissions rates or lb/MWh emissions rates. OR OR Sections 3.2.2 and 5.2 of Appendix A of this subpart.

Sorbent a. Install, operate, and trap maintain the sorbent trap monitoring monitoring system system

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Page 863 of 946 b. Install, operate, and maintain the diluents gas, flow rate, and/or moisture monitoring systems c. Convert emissions concentrations to 30 boiler operating day rolling average lb per MMBtu emissions rates or lb/MWh emissions rates. OR LEE testing OR a. Select sampling ports Single point located at the location and the number 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 and volumetric flow-rate of the stack gas. Method 2, 2F, or 2G at 40 CFR part 60, 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 . Method 3A or 3B at 40 CFR part 60, Appendix A-1 of this chapter, 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. Section 4.1.3 and 5.3 of Appendix A of this subpart.

Section 6 of Appendix A of this subpart.

c. Determine oxygen and carbon dioxide concentrations of the stack gas.

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Page 864 of 946 d. Measure the moisture Method 4 at 40 content of the stack gas. CFR part 60, Appendix A-3 of 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 emission concentration. Method 30B at 40 CFR part 60, Appendix A-8 of this chapter Section 6 of Appendix A of this subpart.

f. Convert emissions concentrations to 30 boiler operating day rolling average lb per MMBtu emissions rates or lb/MWh emissions rates. g. Convert 30 boiler operating day rolling average lb per MMBtu pr lb/MWh to lb per year.

Potential maximum annual heat input in MMBtu or potential maximum electricity generated in MWh

5. Sulfur dioxide (SO2)

SO2 CEMS

a. Install, operate, and PS 2 or 6 at 40 maintain the CEMS CFR 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 maintain the diluents gas, flow rate, and/or moisture monitoring systems c. Convert hourly emissions concentrations to 30 boiler operating day rolling average lb per MMBtu emissions rates Section 4.1.3 and 5.3 of Appendix A of this subpart.

Method 19 Ffactor methodology at 40 CFR part 60, Appendix A-7 of

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Page 865 of 946 or lb/MWh emissions rates. this chapter, or calculate using mass emissions rate and electrical output data.

Table 6 to Subpart UUUUU of Part 63 — Fuel Analysis Requirements As stated in §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:
To conduct a You must ... fuel analysis for the following pollutant ...
1. Mercury (Hg) a. Collect fuel samples. b. Composite fuel samples.

Using ...213

Procedure in §63.10008(c) or ASTM D2234/D2234M (for coal) or equivalent. Procedure in §63.10008(d) or equivalent.

c. Prepare composited EPA SW–846–3020A (for liquid fuel samples. samples) or ASTM D2013/D2013M(for coal)or equivalent. d. Determine heat content of the fuel type. ASTM D5865 (for coal) or equivalent.

e. Determine moisture ASTM D3173 or equivalent. content of the fuel type. f. Measure Hg concentration in fuel sample. ASTM D6722–01 (for coal) or SW– 846–7471A (for solid samples) or SW–846–7470A (for liquid samples) or equivalent.

213

All ASTM, ANSI, and ASME methods are incorporated by reference.
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Page 866 of 946 g. Convert concentration into units of pounds of pollutant per TBtu of heat content or lb per MWh. 2. Other nonHg HAP metals a. Collect fuel samples. b. Composite fuel samples. Method 19 F-factor methodology at 40 CFR part 60, Appendix A-7 of this chapter, or calculate using mass emissions rate and electrical output data. Procedure in §63.10008(c) or ASTM D2234/D2234M (for coal) or equivalent. Procedure in §63.10008(d) or equivalent.

c. Prepare composited EPA SW–846–3020A (for liquid fuel samples. samples) or ASTM D2013/D2013M(for coal) or equivalent. d. Determine heat content of the fuel type. ASTM D5865 (for coal) or equivalent.

e. Determine moisture ASTM D3173 or equivalent. content of the fuel type. f. Measure other non- EPA SW-846-6010B or ASTM D3683 Hg HAP metals (for coal samples) or equivalent; concentrations in fuel EPA SW-846-6010B (for other solid sample. fuel samples) or equivalent; or EPA SW–846–6020 (for liquid fuel samples) or equivalent. g. Convert concentration into units of pounds of pollutant per TBtu of heat content or lb per MWh. b. Composite fuel samples. 3. Hydrogen chloride (HCl) a. Collect fuel samples. b. Composite fuel samples. Method 19 F-factor methodology at 40 CFR part 60, Appendix A-7 of this chapter, or calculate using mass emissions rate and electrical output data. Procedure in §63.10008(d) or equivalent. Procedure in §63.10008(c) or D2234/D2234M (for coal) or equivalent. Procedure in §63.10008(d) or equivalent.

c. Prepare composited EPA SW–846–3020A (for liquid fuel samples. samples), EPA SW-846-3050B (for solid samples), or ASTM D2013/D2013M (for coal) or This document is a prepublication version, signed by EPA Administrator, Lisa P. Jackson on 03/16/2011. We have taken steps to ensure the accuracy of this version, but it is not the official version.

Page 867 of 946 equivalent. d. Determine heat content of the fuel type. ASTM D5865 (for coal) or equivalent.

e. Determine moisture ASTM D3173 or equivalent. content of the fuel type. f. Measure chlorine concentration in fuel sample. g. Convert concentrations into units of pounds of pollutant per MMBtu of heat content or lb per MWh. 4. Hydrogen fluoride (HF) a. Collect fuel samples. b. Composite fuel samples. EPA SW-846-9250 or ASTM D6721 (for coal) or equivalent, or EPA SW846-9250 or ASTM E776 (for solid or liquid samples) or equivalent. Method 19 F-factor methodology at 40 CFR part 60, Appendix A-7 of this chapter, or calculate using mass emissions rate and electrical output data. Procedure in §63.10008(c) or D2234/D2234M (for coal) or equivalent. Procedure in §63.10008(d) or equivalent.

c. Prepare composited EPA SW–846–3020A (for liquid fuel samples. samples), EPA SW-846-3050B (for solid samples), or ASTM D2013/D2013M (for coal) or equivalent. d. Determine heat content of the fuel type. ASTM D5865 (for coal) or equivalent.

e. Determine moisture ASTM D3173 or equivalent. content of the fuel type. f. Measure chlorine concentration in fuel sample. EPA SW-846-9250 or ASTM D6721 (for coal) or equivalent, or EPA SW846-9250 or ASTM E776 (for solid or liquid samples) or equivalent.

Method 19 F-factor methodology at g. Convert 40 CFR part 60, Appendix A-7 of concentrations into this chapter. units of pounds of pollutant per MMBtu of heat content. This document is a prepublication version, signed by EPA Administrator, Lisa P. Jackson on 03/16/2011. We have taken steps to ensure the accuracy of this version, but it is not the official version.

Page 868 of 946

Table 7 to Subpart UUUUU of Part 63 — Establishing Operating Limits As stated in §63.10007, you must comply with the following requirements for establishing operating limits:
If you have an applicable emission limit for ...
1. Particulate matter (PM), mercury (Hg), or other nonHg HAP metals

And your You must ... operating limits are based on ...

Using ...

According to the following requirements

a. Wet scrubber operating parameters

i. Establish a site-specific minimum pressure drop and minimum flow rate operating limit according to §63.10011(c)

(1) Data from the pressure drop and liquid flow rate monitors and the PM, Hg, or other non-Hg HAP metals performance test

(a) You must collect pressure drop and liquid flow-rate data every 15 minutes during the entire period of the 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. (a) You must collect secondary voltage and current and calculate total

b. Electrostatic precipitator operating parameters (option only

i. Establish a site-specific secondary power input according to §63.10011(c)

(1) Data from the secondary power input during the PM, Hg, or

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Page 869 of 946 for units that operate wet scrubbers) other non-Hg HAP metals performance test ESP secondary power input data 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 results obtained from performance testing and are measured continuously using PM CEMS 2. Hydrogen chloride (HCl) or hydrogen fluoride (HF) a. Wet scrubber operating parameters i. Establish a (1) Data from the PM site-specific performance filterable PM test concentration according to §63.10011(d) (a) You must collect at least 3 test runs of Method 5 filterable PM results.

i. Establish a site-specific minimum pH and flow rate operating limits according to §63.10011(c)

(1) Data from the pH and liquid flow rate monitors and the HCl performance test

(a) You must collect pH and liquid flow rate data every 15 minutes during the entire period of the performance tests; (b) Determine the average hourly pH

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Page 870 of 946 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 DSI operating parameters i. Establish a site-specific minimum sorbent injection rate operating limit according to §63.10011(c). If different acid gas sorbents are used during the HCl performance test, the average value for each sorbent becomes the sitespecific operating limit for that sorbent. (1) Data from the sorbent injection rate monitors and HCl or Hg performance test (a) You must collect sorbent injection rate data every 15 minutes during the entire period of the performance tests; (b) Determine the average hourly sorbent injection rates of the three test run averages measured during the performance test.

Table 8 to Subpart UUUUU of Part 63 — Demonstrating Continuous Compliance As stated in §63.10021, you must show continuous compliance with the emission limitations for affected sources according to the following:
If you must meet the following operating limits or work practice standards ... You must demonstrate continuous compliance by ...

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Page 871 of 946

1. Fabric filter bag leak detection operation 2. Wet PM scrubber pressure drop and liquid flow-rate

3. Wet acid gas scrubber pH and liquid flow rate

4. Dry scrubber or DSI sorbent or carbon injection rate

5. Electrostatic precipitator secondary power input

Installing and operating a bag leak detection system according to §63.10010 and operating the fabric filter such that the requirements in §63.10021(a)(9) are met. a. Collecting the pressure drop and liquid flow rate monitoring system data according to §§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 §63.10011(c). a. Collecting the pH and liquid flow rate monitoring system data according to §§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 §63.10011(c). a. Collecting the sorbent or carbon injection rate monitoring system data for the dry scrubber or DSI according to §§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 §63.10011(c). a. Collecting the secondary power input monitoring system data for the electrostatic precipitator according to §§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 §63.10011(c).

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Page 872 of 946

6. Fuel pollutant content

7. Filterable PM as measured through PM CEMS

a. Only burning the fuel types and fuel mixtures used to demonstrate compliance with the applicable emission limit according to §63.10011(c) or (d) as applicable; and b. Keeping monthly records of fuel use according to §63.10021(a). a. Collecting the PM concentration data 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 day rolling average lb per MMBtu emissions rates or lb/MWh emissions rates using Method 19 F-factor methodology at 40 CFR part 60, Appendix A7 of this chapter, or calculate using mass emissions rate and electrical output data; and c. Maintaining the 30 day rolling average lb/ MMBtu emissions rates at or above the operating limits established during the performance test according to §63.10011(d).

Table 9 to Subpart UUUUU of Part 63 — Reporting Requirements As stated in §63.10031, you must comply with the following requirements for reports:
You must submit a(n)
1. Compliance report

The report must contain ...

You must submit the report ...

a. Information required in Semiannually §63.10031(c)(1) through (11) according to the requirements in through (11); and §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

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Page 873 of 946 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 §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 §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 §63.8(c)(7), the report must contain the information in §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 This document is a prepublication version, signed by EPA Administrator, Lisa P. Jackson on 03/16/2011. We have taken steps to ensure the accuracy of this version, but it is not the official version.

Page 874 of 946 include the information in §63.10(d)(5)(i) 2. An immediate startup, shutdown, and malfunction report if you had a startup, shutdown, or malfunction during the reporting period that is not consistent with your startup, shutdown, and malfunction plan, and the source exceeds any applicable emission limitation in the emission standard a. Actions taken for the event; and i. By fax or telephone within 2 working days after starting actions inconsistent with the plan; and ii. By letter within 7 working days after the end of the event unless you have made alternative arrangements with the permitting authority.

b. The information in §63.10(d)(5)(ii)

Table 10 to Subpart UUUUU of Part 63 — Applicability of General Provisions to Subpart UUUUU As stated in §63.10040, you must comply with the applicable General Provisions according to the following:
Citation
§63.1 §63.2 §63.3

Subject
Applicability Definitions

Applies to subpart UUUUU
Yes. Yes. Additional terms defined in §63.10042. Yes.

Units and Abbreviations §63.4 Prohibited Activities Yes. and Circumvention §63.5 Preconstruction Review Yes. and Notification Requirements Yes. Compliance with §63.6(a), (b)(1)(b)(5), (b)(7), (c), Standards and Maintenance (f)(2)-(3), (g), (h)(2)-(h)(9), (i), Requirements (j) §63.6(e)(1)(i) General Duty to No. See §63.10000(b) for minimize emissions general duty requirement. §63.6(e)(1)(ii) Requirement to correct No. malfunctions ASAP §63.6(e)(3) SSM Plan requirements No. §63.6(f)(1) SSM exemption No. This document is a prepublication version, signed by EPA Administrator, Lisa P. Jackson on 03/16/2011. We have taken steps to ensure the accuracy of this version, but it is not the official version.

Page 875 of 946 §63.6(h)(1) §63.7(a), (b), (c), (d), (e)(2)-(e)(9), (f), (g), and (h) §63.7(e)(1) §63.8 63.8(c)(1)(i) §63.8(c)(1)(iii) §63.8(d)(3) §63.9 §63.10(a), (b)(1), (c), (d)(1)-(2), (e), and (f) §63.10(b)(2)(i) SSM exemption Performance Testing Requirements No. Yes.

Performance testing No. See §63.10007. Monitoring Requirements General duty to minimize emissions and CMS operation Requirement to develop No. SSM Plan for CMS Written procedures for Yes, except for last sentence, CMS which refers to an SSM plan. SSM plans are not required. Notification Yes. Requirements Recordkeeping and Yes. Reporting Requirements Recordkeeping of occurrence and duration of startups and shutdowns Recordkeeping of malfunctions No.

§63.10(b)(2)(ii)

§63.10(b)(2)(iii) §63.10(b)(2)(iv) §63.10(b)(2)(v) §63.10(b)(2)(vi) §63.10(b)(2)(vii)(ix) §63.10(b)(3),and (d)(3)-(5) §63.10(c)(7)

Maintenance records Actions taken to minimize emissions during SSM No. Actions taken to minimize emissions during SSM Recordkeeping for CMS Yes. malfunctions Other CMS requirements Yes. No.

No. See 63.10001 for recordkeeping of (1) occurrence and duration and (2) actions taken during malfunction. Yes. No.

Yes. Additional recordkeeping requirements for CMS – identifying exceedances and excess emissions

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Page 876 of 946 §63.10(c)(8) Yes. Additional recordkeeping requirements for CMS – identifying exceedances and excess emissions Recording nature and No. See 63.10032(g) and (h) for cause of malfunctions malfunctions recordkeeping requirements. Recording corrective No. See 63.10032(g) and (h) for actions malfunctions recordkeeping requirements. Use of SSM Plan No. SSM reports No. See 63.10031(h) and (i) for malfunction reporting requirements. Control Device No. Requirements State Authority and Yes. Delegation Yes. Addresses, Incorporation by Reference, Availability of Information, Performance Track Provisions Reserved No.

§63.10(c)(10) §63.10(c)(11) §63.10(c)(15) §63.10(d)(5) §63.11 §63.12 §63.13-63.16

§63.1(a)(5),(a)(7)(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).

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Page 877 of 946

XX.

Appendix A is added to Subpart UUUUU, to read as

follows: Appendix A to Subpart UUUUU—Hg Monitoring Provisions 1. 1.1 General Provisions. 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
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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. 2.1 Monitoring of Hg Emissions for Various Configurations. 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
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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
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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
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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 (Hg0, CAS Number 7439-97-6) and oxidized forms of Hg. 3.1 Definitions.

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3.1.1 CEMS

Mercury Continuous Emission Monitoring System or Hg means all of the equipment used to continuously

determine the total vapor phase Hg concentration. The measurement system may include the following major subsystems: sample acquisition, Hg+2 to Hg0 converter, sample transport, sample conditioning, flow control/gas manifold, gas analyzer, and data acquisition and handling system (DAHS). 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 rate. sampling is a batch process. The

The average Hg concentration

in the stack gas for the sampling period is determined, in units of micrograms per dry standard cubic meter (μg/dscm), based on the sample volume measured by the gas flow meter
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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
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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
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signals accurately.

A zero-level gas (or signal) and an For

upscale gas (or signal) are required for this test.

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 highlevel 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

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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 highFor a Hg CEMS, the high-level gas

level gas are required.

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.
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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 3.2.1 Continuous Monitoring Methods. 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.

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Probe Sample Conversion & Conditioning

Dilution Air Calibration Module Mercury Analyzer

FIGURE A-1. 3.2.1.1 3.2.1.1.1

TYPICAL MERCURY CEMS

Equipment Specifications. 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) TeflonTM, 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 Hg0 converter must be maintained at a sample temperature above the acid gas dew point.
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3.2.1.1.3 3.2.1.1.3.1

Measurement System Components. 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
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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 nonThis document is a prepublication version, signed by EPA Administrator, Lisa P. Jackson on 03/16/2011. We have taken steps to ensure the accuracy of this version, but it is not the official version.

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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),
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digital recorder, or data logger, is required for recording measurement data. 3.2.1.2 3.2.1.2.1 Reagents and Standards. 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 this subpart. procedures required under

Calibration gases with known concentrations Special reagents and

of Hg0 and HgCl2 are required.

equipment may be needed to prepare the Hg0 and HgCl2 gas standards (e.g., NIST-traceable solutions of HgCl2 and gas generators equipped with mass flow controllers). 3.2.1.2.2 3.2.1.2.2.1 Required Calibration Gas Concentrations. 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

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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 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
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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 µg/scm for all coal ranks (including coal refuse) except for lignite; for lignite, use 16 µg/scm. Option 2 is to base the MPC on the results This option may be

of site-specific Hg emission testing.

used only if the unit does not have add-on Hg emission
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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 µg/scm, use the result as the span value. Otherwise, round off the result Alternatively, you may round

to the next highest integer.

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Page 896 of 946

off the span value to the next highest multiple of 10 µg/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
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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 fuelspecific 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 For anthracite coal, use 3.0% H2O;

moisture default value.

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

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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 Set the span value of a CO2 or O2

Moisture Monitors.

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.
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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 §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 midlevel 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

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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

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Page 901 of 946

must either meet the main performance specification or the alternative specification in Table A-1. TABLE A-1: For this required certifica tion test... 7-day calibrati on error test2 REQUIRED CERTIFICATION TESTS AND PERFORMANCE SPECIFICATIONS FOR HG CEMS The main performance specification1 is... The alternate performance specification1 is... |R - A| ≤1.0µg/scm And the conditions of the alternate specification are... -------------The alternate specification may be used on any day of the test. The alternate specification may be used at any gas level

RMavg < 5.0 µg/scm Cycle 15 minutes5 -----------time -------------test2 -1 Note that |R - A|is the absolute value of the difference between the reference gas value and the analyzer reading. |R - Aavg| is the absolute value of the difference between the reference gas concentration and the average of the
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|R - A| ≤ 5.0% of span value, for both the zero and upscale gases, on each of the 7 days Linearity |R - Aavg | ≤ check3 10.0% of the reference gas concentration at each calibration gas level 3-level |R - Aavg | ≤ system 10.0% of the integrity reference gas check4 concentration at each calibration gas level RATA 20.0% RA

|R - Aavg | ≤ 0.8 µg/scm

|R - Aavg | ≤ 0.8 µg/scm

The alternate specification may be used at any gas level

|RMavg - Cavg | ≤ 1.0 µg/scm** ----------------------------

Page 902 of 946

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 µg/m3, for 2 minutes. ** Note that |RMavg - Cavg| 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 NISTtraceable 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
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Page 903 of 946

manner.

Record the monitor response from the data At

acquisition and handling system for each gas injection.

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 A2. 4.1.1.3 Three-Level System Integrity Check. Perform the

3-level system integrity check using low, mid, and highlevel calibration gas concentrations generated by a NISTtraceable source of oxidized Hg. Follow the same basic If moisture and/or

procedure as for the linearity check.

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 The SIE must either meet

(SIE), as described in Table A-2.

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,

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Page 904 of 946

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. stages--upscale and downscale. Perform the test in two

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 µg/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
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appendix A-8 to part 60.

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 µg/dscm. If

the average concentration is ≤ 1.0 µg/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 µg/dscm. If the RD

specification is met, the results of the two samples shall be averaged arithmetically.
RD = C a − Cb C a + Cb x 100

(Eq. A-1)

Where: RD = Relative deviation between the Hg concentrations of samples "a" and "b" (percent) Ca = Hg concentration of Hg sample "a" (μg/dscm) Cb = Hg concentration of Hg sample "b" (μg/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

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Page 906 of 946

the results from a maximum of three runs for calculating relative accuracy. The minimum time per run is 21 minutes If the Ontario Hydro Method, Method

if Method 30A is used.

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 µg/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 A2. 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.
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Page 907 of 946

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 µg/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-2 for Hg CEMS also apply to the sorbent trap monitoring system.
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Page 908 of 946

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 Monitoring systems that are used to measure stack

Systems.

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-3, 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
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Page 909 of 946

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 replacement of a gas analyzer;

recertification include:

complete monitoring system replacement, and changing the location or orientation of the sampling probe. TABLE A-3: MINIMUM REQUIRED CERTIFICATION TESTS AND PERFORMANCE SPECIFICATIONS FOR OTHER MONITORING SYSTEMS Of this auxiliary monitoring system…. O2 or CO2 The main performanc e specificat ion1 is… | R – A | ≤ 0.5% O2 or CO2 for both the zero and upscale gases, on each day of the test The alternate performanc e specificat ion2 is…. -----------And the conditions of the alternate specificat ion are….. ----------------

For this required certificat ion test….. 7-day calibratio n error test

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Page 910 of 946

7-day calibratio n error test

Flow rate

Linearity check

O2 or CO2

| R – A | ≤ 3.0% of calibratio n span value for both the zero and upscale signals, on each day of the test | R – Aavg | ≤ 5.0% of the reference gas value ≤ 15 minutes 10.0% RA

| R – A | ≤ 0.01 in. H2O, for DP-type monitors

The alternate specificat ion may be used on any day of the tests

| R – A | ≤ 0.5% O2 or CO2

----------O2 or CO2 |RMavg Cavg | ≤ 1.0 %O2 or % CO2 RATA Flow rate 10.0% RA ---------- ---------------RATA Moisture 10.0% RA |RMavg ---------Cavg | ≤ -----1.5 %H2O 1 Note that |R - A|is the absolute value of the difference between the reference gas value and the analyzer reading. |R - Aavg| 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 |RMavg - Cavg| 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.
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Cycle time test RATA

O2 or CO2

The alternate specificat ion may be used at any gas level -----------------------------

Page 911 of 946

5.1 5.1.1

Hg CEMS. Required QA Tests. Periodic QA testing of each Hg The

CEMS is required following initial certification. required QA tests, the test frequencies, and the

performance specifications that must be met are summarized in Table A-4, 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 daily. Perform calibration error tests of the Hg CEMS 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 highlevel 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
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Page 912 of 946

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. TABLE A-4: ON-GOING QA TEST REQUIREMENTS FOR HG CEMS At this frequency ... With these qualifications and exceptions... • Use either a mid- or highlevel gas • Use either elemental or oxidized Hg • Calibrations are not required when the unit is not in operation. • Required only for systems with converters • Use oxidized Hg ---either mid- or high-level • Not required if daily calibrations are done with a NIST-traceable source of oxidized Acceptance criteria...

Perform this type of QA test...

Calibration error test

Daily

|R - A| ≤ 5.0% of span value or |R - A| ≤ 1.0µg/scm

Single-level system integrity check

Weekly1

|R - Aavg| ≤ 10.0% of the reference gas value or |R - Aavg| ≤ 0.8 µg/scm

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Page 913 of 946

Hg

Linearity check or 3-level system integrity check

Quarterly3

• Required in each “QA operating quarter”2 ---and no less than once every 4 calendar quarters • 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 • Test deadline may be extended for “non-QA operating quarters,” up to a maximum of 8 quarters from the quarter of the previous test. • 720 operating hour grace period

|R - Aavg | ≤ 10.0% of the reference gas value, at each calibration gas level or |R - Aavg| ≤ 0.8 µg/scm

RATA

Annual4

20.0% RA or |RMavg - Cavg | ≤ 1.0 µg/scm, RMavg < 5.0 µg/scm if

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Page 914 of 946

available
1 2

“Weekly” means once every 168 unit operating hours. 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-4. 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
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Page 915 of 946

the required QA tests in Table A-4 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 5.1.4.1 Grace Periods. 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 The test must be completed once every

integrity checks.

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.
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Page 916 of 946

5.2 5.2.1

Sorbent Trap Monitoring Systems. 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-4 for Hg CEMS shall apply to the annual RATAs of the sorbent trap monitoring system. 5.2.2.3 A 720 unit or stack operating hour grace period is

available for RATAs of the monitoring system. 5.2.2.4 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 The minimum on-going QA test requirements for

Systems.

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Page 917 of 946

these monitoring systems are summarized in Table A-5, 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 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 TABLE A-5: MINIMUM ON-GOING QUALITY ASSURANCE TEST REQUIREMENTS FOR AUXILIARY MONITORING SYSTEMS

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Page 918 of 946

Perform this QA test... Calibration error test

For this monitorin g system... O2 or CO2

At this frequenc y... Daily

With these conditions and exceptions... • Use either a mid or high level gas • Not required on nonoperating days • Not required on nonoperating days

The acceptance criteria are... |R - A| ≤ 1.0% O2 or CO2

Calibration error test

Flow rate

Daily

|R - A| ≤ 6.0% of calibratio n span value or |R - A| ≤ 0.02 in. H2O for a DP-type monitor Must be passed

Interferenc e check

Flow rate

Daily

• Not required on nonoperating days • Required in each QA operating quarter -but no less than once every 4

Linearity check

O2 or CO2

Quarterl y

|R - A| ≤ 5.0% of reference gas or |R - A| ≤ 1.0% O2 or

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Page 919 of 946

calendar quarters • 168 operating hour grace period available Leak check Flow rate Quarterl y • Required only for DP-type flow monitors • Once every four QA operating quarters, not to exceed 8 calendar quarters • Once every four QA operating quarters, not to exceed 8 calendar quarters • Once every four QA operating quarters, not to exceed 8 calendar quarters

CO2

Must be passed

RATA

O2 or CO2

Annual** *

RA ≤ 7.5% or |RMavg – Cavg | ≤ 0.7% O2 or CO2

RATA

Flow rate

Annual** *

RA ≤ 7.5%

RATA

Moisture

Annual** *

RA ≤ 7.5% or |RMavg – Cavg | ≤ 1.0% H2 O

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Page 920 of 946
***

Note that these RATAs can still be passed at RA percentages up to and including 10.0% RA. Alternate specifications of |R - A| ≤ 1.0% O2 or CO2 and |R - A| ≤ 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 5.4.1.1 General Requirements. 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 date,

purpose. The following records should be maintained:

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Page 921 of 946

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 Keep a written record of the procedures

Integrity Checks.

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
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Page 922 of 946

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.

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Page 923 of 946

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 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
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Page 924 of 946

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. 6.1 6.1.1 Data Reduction and Calculations. Data Reduction. Reduce the data from Hg CEMS and (as applicable)

flow rate, diluent gas, and moisture monitoring systems to hourly averages, in accordance with §60.13(h)(2) of this
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Page 925 of 946

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.
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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 Multiply the Hg

the equation selected from Method 19.

concentration value by 6.24 x 10-11 to convert it from µg/scm to lb/scf. 6.2.1.3 Multiply the lb/MMBtu value obtained in section

6.2.1.2 of this appendix by 106 to convert it to lb/TBtu. 6.2.1.4 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
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Page 927 of 946

parameters, using Equation A-2 of this section (for wetbasis measurements of Hg concentration) or Equation A-3 of this section (for dry-basis measurements), as applicable: M h = K C h Qh t h (Equation A-2)

Where: Mh = Hg mass emissions for the hour (lb) K = Units conversion constant, 6.236 x 10-11 lb-scm/µg-scf, Ch = Hourly average Hg concentration, wet basis (µg/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 M h = K C h Qh t h (1 − Bws ) (Equation A-3)

Where: Mh = Hg mass emissions for the hour (lb) K = Units conversion constant, 6.236 x 10-11 lb-scm/µg-scf, Ch = Hourly average Hg concentration, dry basis (µg/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
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operating hour in which valid data are obtained for all parameters.

E ho =

Mh x 103 (MW )h (t h )

(Equation A-4)

Where: Eho = Electrical output-based Hg emission rate (lb/GWh) Mh = Hg mass emissions for the hour, from Equation A-2 or A3 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.) 3 10 = 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 A5 of this section to calculate the Hg emission rate for each averaging period.
n

Eo =

∑E
h =1

ho

n

(Equation A-5)

Where: E o = 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
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Page 929 of 946

all parameters (Note: Do not include non-operating hours with zero emission rates in the average). 7. 7.1 Recordkeeping and Reporting. 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.
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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
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Page 931 of 946

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 7.1.2.2 The date and hour; 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 MWge);
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The hourly gross unit load (rounded to nearest

Page 932 of 946

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 7.1.3.2 The date and hour; 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 (µg/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;
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Page 933 of 946

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 For each affected unit or common stack using a

Systems).

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 7.1.4.2 The date and hour; 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 (µg/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

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Page 934 of 946

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 7.1.5.1 Stack Gas Volumetric Flow Rate Records. 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

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Page 935 of 946

rate data are also needed in order to demonstrate compliance with heat input-based and electrical outputbased 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 7.1.5.2.2 The date and hour; Monitoring system and component identification

codes, as provided in the monitoring plan, if a qualityassured 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.

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Page 936 of 946

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 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 7.1.6.2.2 The date and hour; 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 If the

(percent H2O, rounded to the nearest tenth).

continuous moisture monitoring system consists of wet- and dry-basis oxygen analyzers, also record both the wet- and
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Page 937 of 946

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 7.1.7.1 Records of Diluent Gas (CO2 or O2) Concentration. 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 7.1.7.2.2 The date and hour; Monitoring system and component identification

codes, as provided in the monitoring plan, if a qualityassured O2 or CO2 concentration is obtained for the hour; 7.1.7.2.3 The hourly average O2 or CO2 concentration (in

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Page 938 of 946

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 7.1.8.2 The date and hour; 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;
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Page 939 of 946

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 7.1.9.2 The date and hour; 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
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Page 940 of 946

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
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Page 941 of 946

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

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Page 942 of 946

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 7.2.1 Reporting Requirements. 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;
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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.
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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-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.

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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 7.2.5.3.2 7.2.5.3.3 The date of report generation; Facility identification information; 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.
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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.

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