*****E.O. 128 66 Review**  **– Draft**  **– Do Not Cite, Quote or Release**  **During Review***** 6560

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- P
**ENVIRONMENTAL PROTECTION AGENCY 40 CFR Part 63**  **[ EPA**  **- HQ**  **- OAR**  **- 2006**  **- 0790**  **; FRL -**  ]
**RIN 2060**  **- A**  **M44 National Emission Standards for Hazardous Air Pollutants**  **for Area Sources:**  **Industrial, Commercial, and Institutional Boil ers**  **AGENCY:** Environmental Protection Agency (EPA).
**ACTION:** Final rule.
**SUMMARY:** EPA is pro mulgat ing national emission standards for control of hazardous air pollutants f rom two area source categories : industrial boilers and commercial and institutiona l boilers

. The final emission standards for control of mercury and polycyclic organic matter emissions from coal

- fired area source boilers are based on the maximum achievable control technology . The final emission standards for control of hazardous air p ollutants emissions from biomass

- fired and oil

fired area source boilers are b ased on EPA’s determination as to what constitutes the generally available control technology or management practices

. **EFFECTIVE DATE :**  Th is final rule is effective on [ INSERT TH E
DATE 60 DAYS AFTER PUBLICATION IN THE FEDERAL REGISTER ]. The incorporation by reference of certain publications listed in th is final rule were approved by the director of the Federal**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** *** Page **2** of **255** Register as of [ INSERT THE DATE 60 DAYS AFTER PUBLICATION IN THE
FEDER AL REGISTER ]

. **ADDRESSES:** EPA established a docket under Docket ID No. EPA

– HQ

– OAR

– 200 6

- 0 790 for this action. All documents in the docket are listed o n the http://www.regulations.gov w ebsite . Although listed in the index, some information is not publicly available,
e.g., CBI or other information whose disclosure is restricted by statute. Certain other material, such as copyrighted material, is not placed on the Internet and will be publicly available only in hard copy form. Publicly available docket mate rials are available either electronically through http://www.regulations.gov or in hard copy at EPA’s Docket Center, Public Reading Room, EPA West Building, Room 3334, 1301 Constitution Ave., NW, Washington, DC. This Docket Facility is open from 8:30 a.m. to 4:30 p.m., Monday through Friday, excluding legal holidays. The telephone number for the Public Reading Room is (202) 566

– 1744, and the telephone number for the Air Docket is (202) 566

– 1742.
**FOR FURTHER INFORMATION CONTACT:** M r . James Eddinger , 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, N orth**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** *** Page **3** of **255** Carolina 27711 ; T elephone number : (919) 541

- 5 426 ; F ax number (919) 541

- 54 50 ; e - mail address: eddinger. jim @epa.gov . **SUPPLEMENTARY INFORMATION:** Acronyms and Abbreviations

Btu British thermal unit . The following acronyms and abbreviations are used in this document.

CAA Clean Air Act
CBI Confidential Business Information
CEMS Co ntinuous Emission Monitoring System
CFR Code of Federal Regulations
CO Carbon monoxide

ERT Electronic Reporting Tool

FR Federal Register
GACT Generally Available Control Technology

HAP Hazardous Air Pollutant HCl Hydrogen chloride
ICR Information Collect ion Request kWh k ilowatt hour
MACT Maximum Achievable Control Technology MMBtu/h Million Btu per hour
NAICS North American Industry Classification System
NESHAP National Emission Standards for Hazardous Air**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** *** Page **4** of **255** Pollutants
NOx Nitrogen oxides
NSPS New Source Pe rformance Standards
PM p articulate matter

PM 2.5 f ine particulate matter
POM Polycyclic organic matter
ppm parts per million
RCRA Resource Conservation and Recovery Act
TBtu t rillion British thermal units tpy tons per year
SO 2 s ulfur dioxide
UPL Upper Pred iction limit
VOC volatile organic compound Organization of This Document

. The information i n this preamble is organized as follows: **I. General Information** A. Does this action apply to me? B. Where can I get a copy of this document ? C. Judicial Review **II. Background Information** A. What is the statutory authority and regulatory approach for this final rule? B. What source categories are affected by the standards? C. What is the relationship between this rule and other related na tional emission standards? D. How did we gather information for this rule? E. How are the area source boiler HAP addressed by this rule? **III . Summary of**  **this final rule** A. Do these standards apply to my source?**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** *** Page **5** of **255** B. What is the affected source? C. Whe n must I comply with the final standards? D. What are the MACT and GACT standards? E. What are the Startup, Shutdown, and Malfunction (SSM) requirements? F. What are the initial compliance requirements? G. What are the continuous compliance requirement s? H. What are the notification, recordkeeping and reporting requirements? I. Submission of Emissions Test Results to EPA **I V.**  **Summary of Significant**  **Changes Following**  **Proposal** A. Changes to Subcategories B. Change from MACT to GACT for Biomass and O il Subcategories C . MACT Floor UPL Methodology/Emission Limits D . C larification of Energy Assessment Requirements E . Revised Subcategory Limits F . Demonstrating Compliance G . Affirmative Defense H. Technical/Editorial Corrections **V .**  **Significant Area**  **Source Public Comments and Rationale for**  **Changes to Proposed Rule** A. Legal and Applicability Issues B. CO Limits C. MACT Floor Analysis D. Beyond the Floor Analysis E. GACT Standards F. Subcategories G. Startup, Shutdown, and Malfunction H. Compli ance Requirements I. Cost/Economic I mpacts **VI .**  **Summary of the Impacts of**  **this F**  **inal R**  **ule** A. What are the air impacts? B. What are the cost impact s? C. What are the economic impact s? D . What are the b enefits? E. What are the water and solid waste imp acts? F . What are the energy impacts? **VII . Relationship of this Action to CAA Section 112(c)(6)**  **VIII .**  **Statutory and Executive Order Review** A. Executive Order 12866: Regulatory Planning and Review B. Paperwork Reduction Act C. Regulatory Flexibility Act (RFA) D. Unfunded Mandates Reform Act of 1995 E. Executive Order 13132: Federalism**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** *** Page **6** of **255** F. Executive Order 13175: Consultation and Coordination with Indian Tribal Governments G. Executive Order 13045: Protection of Children from Environmental Health Risks and Safety Risks H. Executive Order 13211: Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution, or Use I. National Technology Transfer and Advancement Act J. Executive Order 12898: Federal Actions to Address Envi ronmental Justice in Minority Populations and Low

- Income Populations K. Congressional Review Act **I. General Information**
A. The regulated c ategories and entities potentially affected by the final standards include: Does this action apply to me?

Categ ory NAICS code 1 Examples of regulated E ntities Any area source facility using a boiler as defined in th is proposed rule. 321 Wood product manufacturing. 11 Agriculture, greenhouses

. 311 Food manufacturing. 327 Nonmetallic mineral product manufactu ring

. 42 4 Wholesale trade, nondurable goods

. 531 Real estate

. 611 Educational services. 813 Religious, civic, professional, and similar organizations. 92 Public administration. 722 Food services and drinking places.**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** *** Page **7** of **255**
62 Health care and social assistance. 1 North American Industry Classification System. 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 whethe r your facility, company, business, organization, etc., is regulated by this action, you should examine the applicability criteria in 40 CFR 63. 11193 of subpart JJJJJJ ( National Emission Standards for Hazardous Air Pollutants for I ndustrial, C ommercial, an d Institution al Boilers Area Sources )
. If you have any questions regarding the applicability of this action to a particular entity, con sult either the delegated regulatory authority for the entity or your EPA regional representative as listed in 40 CFR 63 .13 of subpart A (General Provisions)

. B . In addition to being available in the docket, an electronic copy of t hi s final action will also be available on the Worldwide Web ( WWW ) through the Technology Transfer Net work ( TTN ). Following signature, a copy of the final action will be posted on the TTN’s policy and guidance page for newly proposed or promulgated rules at the following address: http://www.epa.gov/ttn/oarpg . The TTN provides information and Wh ere can I get a copy of this document ?**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** *** Page **8** of **255** technology exchange in various areas of air pollution control.
C
. Under section 307(b)(1) of the CAA, judicial review of this final rule is available only by filing a petition for review in the U.S. Court of Appeals for the District of Columbia Circui t (the Court) by [ Judicial Review

INSERT THE DATE 60 DAYS FROM PUBLICATION IN THE
FEDERAL REGISTER ]. Under CAA section 307(d)(7)(B), only an objection to this final rule that was raised with reasonable specificity during the period for public comment can be raised during judicial review. CAA section 307(d)(7)(B) also provides a mechanism for EPA to convene a proceeding for reconsideration, “[i]f the person raising an objection can demonstrate to EPA that it was impracticable to raise such objection within [the period for public comment] or if the grounds for such objection arose after the period for public comment (but within the time specified for judicial review) and if such objection is of central relevance to the outcome of the rule.” Any person seeking to make such a demonstration to us should submit a Petition for Reconsideration to the Office of the Administrator, Environmental Protection Agency, Room 3000, Ariel Rios Building, 1200 Pennsylvania Ave., NW., Washington, DC 20460, with a copy to the person listed in t he preceding **FOR FURTHER GENERAL Draft 12/10/2010**  **-- This draft has not been formatted or copyedited for**  **Federal Register style.** *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** *** Page **9** of **255 INFORMATION CONTACT**  section, and the Associate General Counsel for the Air and Radiation Law Office, Office of General Counsel (Mail Code 2344A), Environmental Protection Agency, 1200 Pennsylvania Ave., NW., Washington, DC 20004. Note, under CAA section 307(b)(2), the requirements established by this final rule may not be challenged separately in any civil or criminal proceedings brought by EPA to enforce these requirements

. **II. Background Information** 
A. What is the statu tory authority and regulatory approach for th is final rule? Section 112(d) of the CAA requires us to establish NESHAP for both major and area sources of HAP that are listed for regulation under CAA section 112(c). A major source emits or has the potentia l to emit 10 tpy or more of any single HAP or 25
t py or more of any combination of HAP. A n a rea source is a H AP

emitting stationary source that is not a major source

. S ection 112(k) (3)(B) of the CAA calls for EPA to identify

a t least 30 HAP which , as the result of emissions from area
sources, pose the greatest threat to public health in the largest number of urban areas

. EPA implemented this provision in 1999 in the Integrated Urban Air Toxics Strategy (Strategy), (64 FR 38715, July 19, 1999). Specifica lly, i n the Strategy,**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **10** of **255** EPA identified 30 HAP that pose the greatest potential health threat in urban areas , and these HAP are referred to as the “30 urban HAP.” CAA s ection 112(c)(3) requires EPA to list sufficient categories or subcategories of area sourc es to ensure that area sources represent ing 90 percent of the emissions of the 30 urban HAP are subject to regulation

. A primary goal of the Strategy is to achieve a 75 percent reduc tion in cancer incidence attributable to HAP emi tted from stationary sour ces. Under CAA section 112(d)(5), we may elect to promulgate standards or requirements for area sources "which provide for the use of generally available control techno logies [“ GACT ”] or management practices by such sources to reduce emissions of hazardou s air pollutants." Additional information on GACT is found in the Senate report on the legislation (Senate Report Number 101

- 228, December 20, 1989), which describes GACT as : . . . methods, practices and techniques which are commercially available and app ropriate for application by the sources in the category considering economic impacts and the technical capabilities of the firms to operate and maintain the emissions control systems. Consistent with the legislative history, we can consider costs and eco nomic impacts in determining GACT, which is particularly important when developing regulations for source categories that may have many sm all businesses such as these

.**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **11** of **255** Determining what constitutes GACT involves considering the control technologies and mana gement practices that are generally available to the area sources in the source categor y . We also consider the standards applicable to major sources in the analogous source categor y to determine if the control technologies and management practices are tra nsferable 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
gener ally available for the area source categor ies at issue. Finally, as noted above , 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 categ ory. While GACT may be a basis for standards for most types of HAP emitted from area sources, CAA s ection 112(c)(6) requires that EPA list categories and subcategories of sources assuring that sources accounting for not less than 90 percent of the
aggrega te emissions of each of seven specified HAP are subject to standards under CAA section s 112(d)(2) or (d)(4) , which require the application of the more stringent MACT . The seven**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **12** of **255** HAP specified in CAA section 112(c)(6) are as follows: alkylated lead compoun ds, POM , hexachlorobenzene, mercury, polychlorinated biphenyls ( PCBs ) , 2,3,7, 8

- tetrachlorodibenzofurans, and 2,3,7,8

- tetrachlor o dibenzo

- p dioxin. The CAA section 112(c)(6) list of source categories currently includes industrial coal combustion, industrial oil combustion, industrial wood combustion, commercial coal combustion, commercial oil combustion, and commercial wood combustion. ( See 63 FR 17849 (April 10, 1998)

. ) We listed these source categories under CAA section 112(c)(6) based on the
source cate gories’ contribution of mercury and POM

. In the documentation for the CAA section 112(c)(6) listing, the commercial fuel combustion categories included institutional fuel combustion

. (See “1990 Emissions Inventory of Section 112(c)(6) Polluta nts, Final Re port,” April 1998.) As discussed in the preamble to the proposed rule , we concluded we only need ed to address mercury emissions from the coal

- fueled portion of these categories in order to ensure that 90 percent of the aggregate emissions of mercury would be subject to standards under CAA sections 112(d)(2) or 112(d)(4)

. (See 75 FR 31898, June 4, 2010
. ) As discussed in this preamble, based on public**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **13** of **255** comments received, we re - examine d the emission inventory and the need to address POM emissions from the ar ea source sub categories to meet the CAA section 112(c)(6) 90 percent requirement , and concluded we only need to address POM emissions from the coal

fueled portion of these categories under CAA section 112( d )( 2 ) or 112(d)(4)

. With this final rule and the ma jor source boilers rule, we currently believe that we have subjected to regulation at least 90 percent of the CAA section 112(c)(6) 1990 emissions inventory for mercury and POM . Consequently, we are regulat ing coal

- fired

area source boilers under MACT bec ause we need these sources to meet the 90 percent requirement for mercury and POM in CAA section 112(c)(6). The “ MACT ” required by CAA section s 112(d)(2) or 112(d) (4) can be based on the emissions reductions achievable through application of measures, pr ocesses, methods, systems, or techniques including, but not limited to: (1) reducing the volume of, or eliminating emissions of, such pollutants through process changes, substitutions of materials, or other modifications; (2) enclosing systems or processe s to eliminate emissions; (3) collecting, capturing, or treating such pollutants when released from a process, stack, storage or**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **14** of **255** fugitive emission point; (4) design, equipment, work practices, or operational standards as provided in CAA section 112(h); or (5) a combination of the above

. The MACT floor is the minimum control level allowed for NESHAP and is defined under CAA section 112(d)(3). For new sources, MACT based standards cannot be less stringent than the emission control achie ved in practice by the best

- controlled similar source, as determined by the Administrator. The MACT based standards for existing sources can be less stringent than standards for new sources, but they cannot be less stringent than the average emission limi tation achieved by the best performing 12 percent of existing sources in the category or subcategory (for which the Administrator has emission information) for source categories and subcategories with 30 or

more sources, or the best performing 5 sources fo r categories and subcategories with fewer than 30 sources (CAA section 112(d)(3)(A) and (B))

. Although emission standards are often structured in terms of numerical emissions limits, alternative approaches are sometimes necessary and authorized pursuant to CAA section 112. For example, in some cases, physically measuring emissions from a source may be not practicable due to technological and**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **15** of **255** economic limitations. S ection 112(h) of the CAA authorizes the Administrator to promulgate a design, equipment, wor k practice, or operational standard, or combination thereof, 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 prescribe or enforce an emission standard. S ection 112(h)(2) of the CAA provides that the phrase “not feasible to prescribe or enforce an emission standard” includes “ the situation in which the Administrator determines that ... the application of measurement methodology to a particular class of sources is not practicable due to technological and economic limitations.” As noted above in this section of the preamble , we listed industrial coal combustion, industrial oil combustion, industrial wood combustion, commercial coal combustion, commercial oil combus tion, and commercial wood combustion under CAA section 112(c)(6) based on the source categories’ contribution of mercury and POM

. We listed these same categories under CAA section 112(c)(3) for their contribution of mercury, arsenic, beryllium, cadmium, l ead, chromium, manganese, nickel, POM (as 7

- PAH (polynuclear aromatic hydrocarbons)), ethylene dioxide, and PCB s . We have developed final standards to reflect the**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **16** of **255** application of MACT for mercury and POM from coal

- fired area source boilers and have applied GACT for the urban HAP noted above for boilers firing other fuels and for urban HAP (other than mercury and POM) from coal

- fired area source boilers

. B. What source categories are affected by the standards? Th e source categories affected by the standards are in dustrial boilers and commercial and institutional boilers

. Both source categories w ere included in the area source list published on Ju ly 19 , 1999 (6 4 FR 38721 )
. The inclusion of these two source categories on the CAA section 112(c)(3) area

source category list is b ased on 1990 emissions data , as EPA used 1990 as the baseline year for that listing. We describe above in S ection II. A of this preamble the pollutants that formed the basis of the listings. Th is r ule appl ies to all existing and new ind ustrial boilers, institutional boilers, and commercial boilers located at area sources. The industrial boiler source category includes boilers used in manufacturing, processing, mining, refining, or any other industry. The commercial boiler source catego ry includes boilers used in commercial establishments such as stores/malls, laundries, apartments, restaurants, and hotels/motels. The i nstitutional boiler source category**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **17** of **255** includes boilers used in medical centers (e.g., hospitals, clinics, nursing homes), educational and religious facilities (e.g., schools, universities, churches), and municipal buildings (e.g., courthouses, prisons). Boiler means an enclosed combustion device having the primary purpose of recovering thermal energy in the form of
steam or hot water.
C
. What is the relationship between th is rule and other related national emission standards ? Th is rule regulates industrial boilers and institutional / commercial boilers that are located at area sources of HAP

. Today, in a parallel action , a NESHAP for industrial, commercial, and institutional boilers and process heaters located at major sources i s being pro mulgated reflecting the application of MACT. The major source NESHAP regulates emissions of PM (as a surrogate for non

- mercury metals ) , mercury, HCl (as a surrogate for acid gases) , dioxins /furans , and CO (as a surrogate for non

- dioxin organic HAP ) from existing and new major source boilers. This rule covers boilers located at area source facilities. In addition to the major source MACT for boilers being issued today, the Agency is also issuing emission standards today**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **18** of **255** pursuant to CAA section 129 for commercial and industrial solid waste incineration units. In a parallel action, EPA is finaliz ing a solid waste definition rulemaking purs uant to

s ubtitle D of RCRA. That action is relevant to this proceeding because if an industrial, commercial, or institutional boiler located at an area source combusts secondary materials that are “solid waste , ” as that term is defined by the Administrato r under RCRA, those boilers would be subject to section 129 of the CAA, not section 112. As background, in 2007, the United States Court of Appeals for the District of Columbia Circuit (D.C. Circuit) vacated the

“ CISWI Definitions Rule ” (70 FR 55568, Septe mber 22, 2005), which amended the definitions of “commercial and industrial solid waste incinerator (CISWI),” “commercial or industrial waste,” and “solid waste” in 40 CFR 60, subparts CCCC and DDDD, and which EPA issued pursuant to CAA section 129. The C ourt found that the definitions in that rule w ere inconsistent with the CAA. Specifically, the Court held that the term “solid waste incineration unit” in CAA s ection 129(g)(1) “unambiguously include[s] among the incineration units subject to its standard s any facility that combusts any commercial or industrial solid waste material at all

— subject to the four statutory exceptions**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **19** of **255** identified [in CAA s ection 129(g)(1)].” NRDC v. EPA , 489 F.3d at 1257

– 58. Based on the information available to the Agency, we determined that the boilers that are subject to this area source rule combust predominantly coal, oil, or biomass. We have further determined that the boilers subject to this rule may combust non

- hazardous secondary materials that do not meet the definit ion of "solid waste" pursuant to the rulemaking of

s ubtitle D of RCRA. A boiler located at an area source burning any secondary materials considered " solid waste " would be considered a solid waste incin erat ion unit subject to regulation under CAA section 129. In the final area source boiler rulemaking, EPA is providing specific language to ensure clarity regarding the necessary steps that must be followed for combustion units that begin combusting non

- hazardous solid waste materials and become subject to section 129 standards instead of section 112 standards or combustion units that discontinue combustion of non

- hazardous solid waste materials and become subject to section 112 standards instead of section 129 standards

. S ome of the affected sources subject to this rule may also be subject to the NSPS for industrial, commercial, and**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **20** of **255** institutional boilers (40 CFR part 60, subparts Db and Dc)

. EPA codified these NSPS i n 1986, and revised portions of them in 1999 and 2006 . The two NSPS regulate emissions of P M, SO 2 , and

NO X from boilers constructed after June 19, 1984. Sources subject to the NSPS that are located at area source facilities

are also subject to th is rule because th is rule regulates HAP . I n developing t his rule , we have streamlined the monitorin g and recordkeeping requirements to avoid duplicating requirements in the NSPS

. D . How did we gather information for this rule ? We gathered information for this rule from States’ boiler inspection lists , company w ebsites, published literature, State permi ts, current State and Federal regulations , and from an ICR conducted for the major source NESHAP

. After proposal, we received additional emission test reports. We developed an initial nationwide population of area

source boiler s based on boiler inspector data

- base s from 13
S tates . The boiler inspector data

- bases include steam boilers that are required to be inspected for safety or insurance purposes. We classified the area source boilers to NAICS codes based on the “ name ” of the facility at which the boi ler was located

. However, many of the boilers in the boiler inspector**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **21** of **255** data

- base could not be readily assigned to an NAICS code

. We reviewed S tate and other F ederal regulations that apply to the area sources in the source categories for information

conce rning existing HAP emission control approaches. For example, as noted above, the NSPS for small industrial, commercial, and institutional boilers in 40 CFR part 60, subpart
Dc apply to boilers at some area sources. Similarly, permit requirements establis hed by the Ohio, Illinois, Vermont, New Hampshire, and Maine air regulatory agencies apply to some area

s ources. We also reviewed standards for boilers at major

sources that would be appropriate for and transferable to boiler s at area sources. For exampl e, we determined that management practices , such as, annual tune

- ups and operator training applicable to major source boilers are equally feasible for boilers at area sources.
E . How are the area source boiler HAP addressed by this rule ?
A s explained in S ection II.A of this preamble , industrial coal combustion, industrial oil combustion, industrial wood combustion, commercial coal combustion, commercial oil combustion, and commercial wood combustion are listed under CAA section 112( c)(6) due to contributions of mercury and POM and these same categories are listed under CAA section 112(c)(3) for**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **22** of **255** their contribution of mercury, arsenic, beryllium, cadmium, lead, chromium, manganese, nickel, POM, ethylene dioxide, and
PCB. With respect to the CAA section 112(c) (3) pollutants, we used su rrogates b ecause , as explained in this section of the preamble , it was not practical to establish individual standards for each specific HAP. We grouped the CAA section 112(c)(3) pollutants , which formed the basis for the listing of these two source categories, into three common groupings : mercury, non
mercury metallic HAP (arsenic, beryllium, cadmium, chromium, lead, manganese, and nickel) , and organic HAP (POM, ethylene dichloride, and PCB ) . In general , the pollutants within each group have similar characteristics and can be controlled with the same techniques. For the non

- mercury metallic HAP, we selected PM as a surrogate. Th e inherent variability and unpredictability of the

non - mercury metal HAP compositions and amounts in fuel has a material effect on the composition and amount of non - mercury metal HAP in the emissions from the boiler. As a result, establishing individual numerical emissions limit s for each non mercury HAP metal species is diffi cult given the level of uncertainty about the individual non

- mercury metal HAP**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **23** of **255** compositions of the fuels that will be combusted. An emission characteristic common to all boiler s is that the non - mercury metal HAP are a component of the PM contained in the fly ash emitted from the boiler. A sufficient correlation exists between PM and non

- mercury metallic HAP to rely on PM as a surrogate for these HAP and for their control. Therefore, the same control techniques that would be used to control the fly

ash PM will control non

- mercury metallic HAP. Emission s limits established to achieve control of PM w ill also achieve control of non - mercury metal lic HAP. Furthermore, establishing separate standards for each individual HAP would impose costly and significantl y more complex compliance and monitoring requirements and achieve little, if any, HAP emissions reductions beyond what would be achieved using the surrogate pollutant approach. For organic urban HAP, we selected CO as a surrogate for organic compounds , i ncluding POM, emitted from the various fuels burned in boilers. The presence of CO is an indicator of incomplete combustion. A high level of CO in emissions is a potential indication of elevated organic HAP emissions. Monitoring equipment for CO is read ily available, which is not the case for organic HAP. Also, it is significantly easier and**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **24** of **255** less expensive to measure and monitor CO emissions than to measure and monitor emissions of each individual organic HAP. We considered other surrogates, such as to tal hydrocarbon ( THC ), but lacked data on emissions and permit limits for area source boilers. Therefore, using CO as a surrogate for organic urban HAP is a reasonable approach because minimizing CO emissions will result in minimizing organic urban HAP em issions. Based on these considerations, we are promulgating GACT standards for PM (as a surrogate for the individual urban metal

HAP ) for coal, biomass, and oil

- fired boilers and CO (as a surrogate pollutant for the individual urban organic HAP) f or biom ass - fired and oil

- fired boilers. We are also establishing MACT standards for mercury and for POM (using CO as a surrogate pollutant) f o r coal

- fired boilers. The MACT standard for POM from coal

- fired boilers would also be GACT for urban organic HAP other than POM.
**III .**  **Summary of this**  **F inal**  **R rule** 
A. Do the se standards apply to m y source ? Th is rule applies to you if you own or operate a boiler combusting solid fossil fuels , biomass, or liquid fuels located
at an area source. The st andards do not apply to boilers that are subject to another standard under 40 CFR part 63 or to a**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **25** of **255** standard developed under CAA section 129. Th is rule applies to you if you own or operate a boiler combusting natural gas, located at an area source, that swi tches to combusting solid fossil fuels , biomass, or liquid fuel after June 4, 2010
. B . What is the affected source ? This final rule affects industrial boilers, institutional boilers, and commercial boilers. The affected source is the collection of all existing b oiler s within a subcategory located
at a n area source facility or each new boiler located at an area source facility

. C. When must I comply with the se standards? The owner or operator of an existing source subject to a work practice or manageme nt practice standard of a tune

- up is required to comply with this final rule no later than [ INSERT
THE DATE 1 YEAR AFTER THE DATE OF PUBLICATION IN THE FEDERAL
REGISTER ]

. The owner or operator of an existing source subject to emission limits or an energy assessment requirement is required to comply with this final rule no later than [ INSERT THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION IN THE FEDERAL
REGISTER ]. The owner or operator of a new source is required to comply on [ INSERT THE DATE 60 DAYS AFTER THE DATE OF PUBLICATION**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **26** of **255** IN THE FEDERAL REGISTER ] or upon startup of the facility , whichever is later. Owners and operators subject to 40 part CFR 60, subpart CCCC or subpart DDDD who cease combusting solid waste must be in compliance with this subpart on the effective date that the unit ceased combusting solid waste , consistent with 40 CFR part 60, subpart CCCC or subpart DDDD

. D . What are the MACT and GACT standards ? Emission standards are in the form of numerical emission limits for new and existing area source boiler s. The MACT emission limits for mercury and CO (as a surrogate for POM) are presented , along with the GACT emission limit s for PM (as a surrogate for urban metals), in Table 1 of this preamble

. The units are pounds of PM or mercury per million British thermal units ( lb/ MM Btu ) and ppm for CO. **Table 1. Emission Limits for Area Source Boilers**

**Subcategory Heat Input**  **(MMBtu/h) Pollutants**  **Emission Limits** New coal

fired boiler ≥ 30 a. Particulate Matter

b. Mercury

c. Carbon Monoxide 0.03 lb per MMBtu of heat input. 0. 0000048 lb per MMBtu of heat input. 400 ppm by volume on a dry basis corrected to 3 percent oxygen.**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **27** of **255**
≥ 10 and < 30 a. Particulate Matter

b. Mercury

c. Carbon Monoxide 0.42 lb per MMBtu of hea t input. 0.0000048 lb per MMBtu of heat input. 400 ppm by volume on a dry basis corrected to 3 percent oxygen . New biomass

fired boile r ≥ 30 Particulate Matter 0.03 lb per MMBtu of heat input.

≥ 10 and < 30 Particulate Matter 0. 0 7 lb per MMBtu o f heat input.

New oil

fired boiler ≥ 30 Particulate Matter 0.03 lb per MMBtu of heat input.

≥ 10 and < 30 Particulate Matter 0. 03 lb per MMBtu of heat input. Existing coal

- Fired boiler ≥ 10 a. Mercury

b. Carbon Monoxide 0.0000048 lb per MM Btu of heat input. 400 ppm by volume on a dry basis corrected to 7 percent oxygen. The emission limits for PM apply only to new boilers. The emission limits for mercury and CO apply only to boilers in the coal subcategory ; t he emission limits for exis ting area source boilers in the coal subcategory are applicable only to area source boilers that have a designed heat input capacity of 10 million MM Btu/h or greater . If your boiler burns any solid fossil fuel and no more than**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **28** of **255** 15 percent biomass on a tot al fuel annual heat input basis, the boiler is in the coal subcategory. If your boiler burns at least 15 percent biomass on a total fuel annual heat input basis, the unit is in the biomass subcategory. If your boiler burns any liquid fuel and is not in e ither the coal or biomass subcategory, the unit is in the oil subcategory, except if the unit burns oil only during periods of gas curtailment. As allowed under CAA section 112(h), a work practice standard is being pro mulgated for new and existing coal

- fi red

area source boilers with a designed heat input capacity of less than 10 MM B tu/h

. T he work practice standard for new and existing coal

- fired area source boilers require s the implementation of a tune

- up program . We are also requiring all biomass

- fired and oil

- fired area source boilers to implement a
tune

- up program as a management practice.

A n additional standard is being pro mulgated for existing area source facilities having an affected boiler with a designed heat input capacity of 10 MMBtu/h or great er that require s the performance of an energy a ssessment , by qualified personnel, on the boiler and its energy us e systems to identify cost

- effective energy conservation measures.**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **29** of **255**
E. What are the Startup, Shutdown, and Malfunction (SSM) requirements? The United States Court of Appeals for the District of Columbia Circuit vacated portions of two provisions in EPA’s CAA

s ection 112 regulations governing the emissions of HAP during periods of startup, shutdown, and malfunction (SSM). S ierra Club v. EPA , 551 F.3d 1019 (D.C. Cir. 2008), cert. denied, 130 S. Ct. 1735 (U.S. 2010) . Specifically, the 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 R ule” (40 CFR 63, subpart A), that EPA promulgated under CAA section 112 of the CAA. When incorporated into CAA s ection 112(d) regulations for specific source categories, these two provisions exempt ed sources from the requirement to comply with the otherwi se applicable CAA section 112(d) emission standard during periods of SSM. Consistent with Sierra Club v. EPA , EPA has established standards in this rule that apply at all times. EPA has attempted to ensure that we have not incorporated into the regulatory language any provisions that are inappropriate, unnecessary, or redundant in the absence of an SSM exemption. In establishing the standards in this rule, EPA has taken**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **30** of **255** into account startup and shutdown periods and, for the reasons explained below , has e stablished differen t standards for those periods. EPA has revised this final rule to require sources to perform only work practice standards, including following the manufacturer’ s recommended procedures, to demonstrate compliance with the CO emission li mits for new and existing area source coal

- fired boilers during periods of startup and shutdown. As discussed in Section VI.G of this preamble, we considered whether continuous emission monitoring or performance testing would be feasible for area source b oilers during periods of startup, shutdown, and malfunction. This final rule only requires emission limits for mercury and CO for existing coal

fired boilers. With regards to performance testing , EPA determined that it is not technically feasible to requ ire stack testing

- in particular, to repeat the multiple required test

runs - during periods of startup and shutdown due to physical limitations and the short duration of startup and shutdown periods. Therefore, we have established the separate work
prac tice standard s for periods of startup and shutdown

. Periods of startup, normal operations, and shutdown are all predictable and routine aspects of a source’s operations.**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **31** of **255** However, by contrast, malfunction is defined as a “sudden, infrequent, and not reason ably 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 court upheld as reasonable standards that had factored in variability of emissions under all operating conditions. However, nothing in section 112(d) or in case law requires that EPA anticipate and account for the innumerable types of potential malfunction events in setting emission standards.
See , Weyerhaeuser v Costle , 590 F.2d 1011, 1058 (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 ce rtain 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**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **32** of **255** administrative exercise of ca se - 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 s ection 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. Similarly, although standards for

area sources are generally not required to be set based on “best performers,” we believe that what is "generally availa ble" should not be based on periods in which there is a “failure to operate.” Moreover, even if malfunctions were considered a distinct operating mode, we believe it would be impracticable to take malfunctions into account in setting CAA section 112(d)

s tandards for area source boilers . 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**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **33** of **255**

sources in the category. Moreover, malfunctions can vary in frequency, degree, and duration, further complicating standard setting. In the event that a source fails to comply with the applicable CAA section 112(d) standards as a result of a malfunction event (s ee 40 CFR 63.2 (definition of malfunction),

EPA must 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 we ll 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 “ca used in part by poor maintenance or careless operation.” ( See 40 CFR 63.2 (definition of malfunction). ) Finally, EPA recognizes that even equipment that is properly designed and maintained can sometimes fail and that such failure can sometimes cause an exceedance of the relevant emission standard. ( See, e.g., State Implementation Plans: Policy Regarding Excessive Emissions During Malfunctions, Startup, and Shutdown (Sept ember 20, 1999); Policy on Excess**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **34** of **255** Emissions During Startup, Shutdown, Maintenance, and
M alfunctions (Feb ruary 15, 1983)). EPA is therefore adding to this final rule an affirmative defense to civil penalties for exceedances of emission limits that are caused by malfunctions. ( See 40 CFR 63. 112 26 (defining "a ffirm ative 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
procee ding).) We also have added other regulatory provisions to specify the elements that are necessary to establish this affirmative defense; the source must prove by a preponderance of the evidence that it has met all of the elements set forth in 63. 1122 6 . ( See 40 CFR 22.24 .) The criteria ensure that the affirmative defense is available only where the event that causes an exceedance of the emission limit meets the narrow definition of malfunction in 40 CFR 63.2 (sudden, infrequent, not 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, short, infrequent, and unavoidable failure**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **35** of **255** 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 emission s in accordance with 40 CFR 63. 112 05(a) 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 ex ceeded...” 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 th e 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 s ection 113 of the CAA (see also 40 CFR 22.77).
F . What are the initial compliance requirements ?
For new and existing area source boilers with applicable emission limit s , you must c onduct initial performance tests to determine compliance with the PM , mercury , and CO emissi on limits. The performance tests to demonstrate compliance with**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **36** of **255** the mercury emission limit can be either a stack test, which also requires a fuel analysis, or only a fuel analysis. As part of the initial compliance demonstration, you must monitor speci fied operating parameters during the i nitial performance tests that demonstrate compliance with the PM , mercury , and CO emission limits f or area source boilers

. The test average establishes your site

- specific operating levels.
For owner s or operator s of existing and new coal

- fired area

source boiler s having a heat input capacity of less than 10 MMBtu/h and all existing and new biomass

- fired and oil

- fired area source boilers, you must submit to the delegated authority or EPA, as appropriate, documentation that a tune

- up was conducted

. For owners or operators of existing area source facilities having a boiler with a heat input capacity of 10 MMBtu/h or greater and s ubject to this rule, you must submit to the delegated authority or EPA, as appropriate, docum entation that the energy assessment was performed and the cost

- effective energy conservation measures identified.
G
. What are the continuous compliance requirements ? If you demonstrate initial compliance with the emission limits by performance (stack) te sts, then you must conduct stack**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **3 7**  of **255** tests on an annual basis. Furthermore, t o demonstrate continuous compliance with the PM , CO, and mercury emission limits, you must monitor and comply with the applicable site

specific operating limits.
For area source boi lers that must comply with the PM and
mercury emission limit s , you must continuously monitor opacity and maintain the opacity at or below 10 percent ( daily block average) or: 1. If the boiler is controlled with a fabric filter, the fabric filter may be contin uously operated such that the alarm on the bag leak detection system does not sound more than 5 percent of the operating time during any 6

- month period. 2. If the boiler is controlled with an electrostatic precipitator (ESP), you must maintain the minimum vol tage and secondary amperage (or total power input) of the ESP at or above the minimum operating limits established during the performance test. 3. If the boiler is controlled with a wet scrubber, you must monitor pressure drop and liquid flow rate of the scru bber and maintain the daily block averages at or above the minimum operating limits established during the performance**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **38** of **255**
test. 4. For boilers with sorbent or carbon injection systems which must comply wi th an applicable mercury emission limit, you must maintain the daily block averages at or above the minimum sorbent flow rate , as calculated according to 40
CFR 63.11221(a)(5). If you elected to demonstrate initial compliance with the mercury emission limit by fuel analysis , as determined accor ding to 40 CFR 63 .11211(b) , you must conduct a monthly fuel analysis and maintain the annual average at or below the limit indicated in Table 1 of this preamble. For boilers that demonstrate compliance with the PM and
mercury emission limit s by performance (stack) tests , you must maintain monthly fuel records that demonstrate that you burned no new fuel type or new mixture (monthly average) as set during the performance test. If you plan to burn a new fuel type or new mixture that is different from what was burned durin g the initial performance test, then you must conduct a new performance test to demonstrate continuous compliance with the

PM emission limit and m ercury emission limit

. Biomass and oil

- fired boilers must meet the management practice standards defined in Ta ble 2 to 40 CFR part 63 , subpart**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **39** of **255**
JJJJJJ . H . What are the notification, recordkeeping and reporting requirements ? All new and existing sources w ill be required to comply with some requirements of the General Provisions (40 CFR part 63, subpart A), which ar e identified in Table 6 to s ubpart
JJJJJJ . The General Provisions include specific requirements for notifications, recordkeeping , and reporting. If performance tests are required under s ubpart JJJJJJ , then the notification and reporting requirements for performance tests in the General

P rovisions also apply. Each owner or operator is required to submit a notification of compliance status report, as required by 40 CFR 63.9(h) of the General Provisions. Subpart JJJJJJ rule requires the owner or operator to include in the notification of compliance status report certifications of compliance with rule requirements. If your unit is subject to an emission limit, then y ou must
prepare, by March 1 of each year, an annual compliance certification report for the pr evious calendar year certifying the truth, accuracy and completeness of the notification and a statement of whether the source has complied with all the relevant standards and other requirements of this subpart

.**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **40** of **255** Th is rule require s records to demonstrate co mpliance with each emission limit, work practice standard, and management practice. These recordkeeping requirements are specified directly in the General Provisions to 40 CFR part 63

. Records for applicable management practices must be maintained. Speci fically, the owner or operator must keep records of the dates and the results of each boiler tune

- up . Records are required for either continuously monitored parameter data for a control device , if a device is used to control the emissions , or continuous op acity monitoring system ( COMS ) data. Each owner and operator is required to keep the following record s : (1) All reports and notifications submitted to comply with this final rule ; (2) Continuous monitoring data as required in this final rule ; (3) Each instance in which you did not meet each emission limit, work /management practice, and operating limit (i.e., deviations from this final rule ); (4) Monthly fuel use by each boiler including a description of the type(s) of fuel(s) burned, amount of each**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **41** of **255** fu el type burned, and units of measure; (5) A copy of the results of all performance tests, energy

a ssessment s, opacity observations, performance evaluations, or other compliance demonstrations conducted to demonstrate initial or continuous compliance with this final rule ; and (6) A copy of your site

- specific monitoring plan developed for this final rule , if applicable.

R ecords must be retained for at least 5 years

. In addition, monitoring plans, operating and maintenance plans, and other plans must be u pdated as necessary and kept for as long as they are still current.
I. Submission of Emissions Test Results to EPA Compliance test data are necessary for many purposes including compliance determinations, development of emission factors, and determining annual emission rates. EPA has found it burdensome and time consuming to collect emission test data because of varied locations for data storage and varied data storage methods. One improvement that has occurred in recent years is the availability of st ack test reports in electronic format as a replacement for bulky paper copies. In this action, we are taking a step to improve data**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **42** of **255** accessibility for stack tests (and in the future continuous monitoring data). Boiler area sources are required to submit t o WebFIRE (an EPA electronic data base ) an electronic copy of stack test reports as well as process data. Data entry requires only access to the Internet and is expected to be completed by the stack testing company as part of the work that it is
contracte d to perform. Please note that the requirement to submit source test data electronically to EPA does not require any additional performance testing. In addition, when a facility submit s performance test data to WebFIRE, there are no additional requiremen ts for data compilation; instead, we believe industry

w ill greatly benefit from improved emissions factors, fewer information requests, and better regulation development as discussed below. Because the information that is be ing reported is already require d in the existing test methods and is necessary to evaluate the conformance to the test methods, facilities are already collecting and compiling these data. T he Electronic Reporting Tool ( ERT ) was developed with input from stack testing companies , who alr eady collect and compile performance test data electronically

. One major advantage of

s ubmit ting source test data through ERT is that it provide s a**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **43** of **255** standardized method to compile and store all the documentation required by s ubpart JJJJJJ

. Another importa nt benefit of submitting these data to EPA at the time the source test is conducted is that these data should reduce the effort involved in data collection activities in the future for th ese source categor ies

. This results in a reduced burden on both affe cted facilities (in terms of reduced manpower to respond to data collection requests) and EPA (in terms of preparing and distributing data collection requests). Finally, another benefit of submit ting these data to WebFIRE electronically is that these data will greatly improve the overall quality of the existing and new emissions factors by supplementing the pool of emissions test data upon which emissions factors are based and by ensuring that data are more representative of current industry operational pr ocedures. A common complaint we hear from industry and regulators is that emissions factors are out

dated or not representative of a particular source category. Receiving recent performance test results would ensure that emissions factors are updated and more accurate. In summary, receiving these test data already collected for other purposes and using them in the emissions factors development program will

save industry, State/local/tribal agencies, and EPA time and**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **44** of **255**
money. As mentioned earlier, the elec tronic data base that will be used is EPA’s WebFIRE, which is a Web site accessible through
EPA’s TTN ( technology transfer network). The WebFIRE website was constructed to store emissions test data for use in developing emission factors. A description of the WebFIRE data base can be found at http://cfpub.epa.gov/oarweb/index.cfm?action=fire.main

. The ERT will be able to transmit the electronic report through EPA’s Central Data Exchange ( CDX ) network for storage in the WebFIRE data base. Although ERT is not the only electronic interface that can be used to submit source test data to the CDX for entry into WebFIRE, it makes submittal of data very straightforward and easy. A description of the ERT can be found at http://www.epa.gov/ttn/chief/ert/ert

_ tool.h tml

. The ERT can be used to document the conduct of stack tests for various pollutants including PM, mercury, dioxin/furan, and HCl. Presently, the ERT does not accept opacity data or CEMS data.
**I V.**  **Summary of Significant**  **Changes Following**  **Proposal**
A. C hanges to Subcategories We have redefined the coal, biomass and oil sub categories**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **45** of **255** for area source bo ilers to clarify the fuel

- type inputs that would define each s ub category. The proposed rule defined the biomass subcategory to include any boiler that burn s any amount of biomass, either alone or in combination with a liquid or gaseous fuel. This definition excluded boilers that burned biomass with coal ; boilers burning greater than 10 percent coal on an annual fuel heat input basis were defined under the c oal

fired subcategory. This final rule defines the biomass subcategory to include any boiler that burns at least 15 percent of biomass on an annual heat input basis. Similarly, the proposed rule defined the oil subcategory to include any boiler that bur ns any liquid fuel either alone or in combination with gaseous fuels, and excluded boilers that burned solid fossil fuels (coal). We have revised this final rule to define the oil subcategory to include any boiler that burns any liquid fuel and is not in either the biomass or coal subcategory. The coal subcategory in this final rule has been revised to include any boiler combusting any solid fossil fuels and no more than 15 percent biomass

. This final rule defines s olid fossil fuels to include , but not limited to, coal, petroleum coke, and tire derived fuel ( TDF ).**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **46** of **255**
B . Change from MACT to GACT for Biomass and Oil Subcategories The proposed rule set MACT

- based emission limits for CO (as a surrogate pollutant for the individual urban organic HAP) from

new and existing biomass

- fired and oil

- fired boilers. With respect to POM from area source boilers classified as biomass

fired or oil

- fired, as well as with respect to other urban HAP besides POM, we have revised this final rule standards t o reflect GACT for these two area source sub categories (see Section V.D of this preamble)

. We are implementing management practice standards, as allowed by CAA section 112(d)(5), for control of POM from new and existing area source boilers in the biomass and oil subcategor ies. The management practice standard requires the implementation of a tune

- up program. C. MACT Floor UPL Methodology/ Emission Limits At proposal, we use d a 99 percent UPL calculation to determine variability. In this final rule , we have determined th at 99 percent UPL is appropriate for fuel based HAP and a 99.9 percent UPL is appropriate for combustion dependent HAP (i.e.,
CO )
. We have modified our assumptions when results of the skewness and kurtosis tests result in a tie between normal and log

- norm al calculations, or when there is not enough data to complete the skewness and kurtosis tests, to choose the log

-**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **47** of **255** normal results. We have also revised the UPL calculation to convert log

- normally distributed data to an arithmetic mean instead of a geometric mean. Further, for fuel based HAP (i.e., mercury), we have implemented an additional fuel variability factor in the emission limits

. D . Clarification of Energy Assessment Requirements The proposed rule required owners and operators of existing

area s ource boilers with a heat input capacity of 10 MMBtu/h and greater to have an energy assessment p erformed by a qualified professional. The proposed rule defined an energy assessment as

an " in

- depth assessment of a facility to identify immediate and long

- t erm opportunities to save energy, focusing on the steam and process heating systems which involves a thorough examination of potential savings from energy efficiency improvements, waste minimization and pollution prevention, and productivity improvement

. " The requirements for the energy assessment, defined in Table 3 of the proposed rule, included visual ly inspecti ng the boiler system , establish ing operating characteristics and energy system specifications , identify ing the boiler’s major energy consuming s ystems, list ing maj or energy conservation measures, and a comprehensive report detailing the ways to improve efficiency, the cost of specific**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **48** of **255** improvements, and the benefits associated with such. This final rule requires an energy assessment for all exis ting boilers with a heat input capacity of 10 MMBtu/h or greater , and clarifies the definition of energy assessment with respect to the requirements of Table 3 of this final rule . The revised definition provid es a maximum duration for performing the energ y assessment and defin es the evaluation requirements for each boiler system and energy use system. These requirements are based on the total annual heat input of the affected boilers. This final rule requires an energy assessment for facilities with aff ected boilers using less than 0.3 trillion Btu per year heat input to be one day in length maximum. The boiler system and energy use system accounting for at least 50 percent of the energy output from the boiler s must be evaluated to identify energy savin gs opportunities within the limit of performing a one day energy assessment. An e nergy a ssessment for a facilit y with affected boilers using 0.3 to 1 TBtu/year
must be three days in length maximum. From these boilers, t he boiler system and any energy use system accounting for at least 33 percent of the energy output will be evaluated, within the limit of performing a three day energy assessment. For**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **49** of **255** f acilities with affected boilers using greater than 1 TBtu /year heat input , the energy assessment must com prise the boiler system and any energy use system accounting for at least 20 percent of the energy output to identify energy savings opportunities. We have also added a definition for "energy use systems" to clarify the components , in addition to the boi ler system , which must be considered during the energy assessment.

E . Revised Subcategory Limits

T he MACT emission limits for the coal subcategor y have been revised based on the revised MACT floor approach (see Section V of this preamble). The revised l imits ensure that the MACT floors can be achieved by all units within a subcategory using appropriate emission reduction strategies , and r eflect achievable emissions reductions for boilers of varying capacities

. The proposed rule set emission limits for PM (as a surrogate for the individual urban metal HAP) for all new area source boilers and CO (as a surrogate pollutant for the individual urban organic HAP) for all new area source boilers and for existing area source boilers with a heat input capacity of 1 0 MMBtu/h or greater . The proposed rule also set emission**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **50** of **255** limits for mercury from new and existing coal

- fired boilers.

In this final rule , the PM emission limits for new area source boilers have been revised based on the size category. For new boilers in the coal, biomass, and oil subcategories with a heat input capacity less than 10 MMBtu/h, GACT is a management practice of a tune

- up. For new boilers between 10 and 30 MMBtu/h heat input, the PM limit has been revised to reflect the performance of GACT , which is a multiclone . The emission limits for mercury and CO have been revised for new and existing coal

fired boilers with a heat input capacity greater than 10 MMBtu/h. Existing and new boilers in the biomass and oil subcategories are not required t o meet emission limits for CO in this final rule ; these units must meet the management practice standards in Table 2 of 40 CFR part 63 , subpart JJJJJJ . Table 2 of this preamble summarizes the revised emission limits for each pollutant for each subcategory

. **Table 2. Revised Emission Limits for Subpart JJJJJJ**

**Subcategory Heat Input**  **(MMBtu/hr) Pollutant**  **Proposed Emission**  **Limit Final**  **Emission Limit**  New coal

fired boiler ≥ 30 Particulate Matter

Mercury 0.03 lb per MMBtu of heat input. 0.000003 lb per 0.03 lb per MMBtu of heat input.

0. 0000048 lb per MMBtu of h eat**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **51** of **255**

Carbon Monoxide MMBtu of heat input. 310 ppm by volume on a dry basis corrected to 7 percent oxygen . input.

400 ppm by volume on a dry basis corrected to 3 percent oxygen .

≥ 10 and < 30 Particulate Matter

Mercury

Carbon Monoxide 0.03 lb per MMBtu of heat input. 0.000003 lb per MMBtu of heat input. 310 ppm by volume on a dry basis corre cted to 7 percent oxygen . 0.42 lb per MMBtu of heat input.

0. 0000048 lb per MMBtu of heat input.

400 ppm by volume on a dry basis corrected to 3 percent oxygen.

New biomass

fired boiler ≥ 30 Particulate Matter

Carbon Monoxide 0.03 lb per MMBtu of heat input. 100 ppm by volume on a dry basis corrected to 7 percent 0.03 lb per MMBtu of heat input.

Management Practice Standards (see Table 2 to subpart JJJJJJ )**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **52** of **255**
oxygen . ≥ 10 and < 30 Particulate Matter

Carbon Monoxide 0.03 lb per MMBtu of h eat input. 100 ppm by volume on a dry basis corrected to 7 percent oxygen . 0. 07 lb per MMBtu of heat input.

Management Practice Standards (see Table 2 to subpart JJJJJJ )

New oil

fired boiler ≥ 30 Particulate Matter

Carbon Monoxide 0.03 lb per MMBt u of heat input. 1 ppm by volume on a dry basis corrected to 3 percent oxygen . 0.03 lb per MMBtu of heat input.

Management Practice Standards (see Table 2 to subpart JJJJJJ )

≥ 10 and < 30 Particulate Matter

Carbon Monoxide 0.03 lb per MMBtu of he at input. 1 ppm by volume on a dry basis corrected to 3 percent oxygen . 0. 03 lb per MMBtu of heat input.

Management Practice Standards (see Table 2 to subpart JJJJJJ )

Existing coal

- Fired ≥ 10 Mercury 0.0000 03 lb per 0.000012 lb per MMBtu of heat**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **53** of **255** boiler

Carbon Monoxide MMBtu of heat input. 310 ppm by volume on a dry basis corrected to 7 percent oxygen . input.

400 ppm by volume on a dry basis corrected to 3 percent oxygen .

Existing biomass

fired boiler Carbon Monoxide 160 ppm by volume on a d ry basis corrected to 7 percent oxygen . Management Practice Standards (see Table 2 to subpart JJJJJJ )

Existing coal

- fired boiler Carbon Monoxide 2 ppm by volume on a dry basis corrected to 3 percent oxygen . Management Practice Standards (see Table 2 to s ubpart JJJJJJ )

F . Demonstrating Compliance We have revised the compliance dates for existing affected sources according to the applicable provisions for each affected

source (e.g., work practice standards, emission limits, management practice standards , and/or an energy assessment)

. Under the proposed rule, owners and operators of existing sources would have had to comply with this final rule within 3**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **54** of **255** years following [ INSERT THE DATE OF PUBLICATION IN THE FEDERAL
REGISTER ]. This final rule requires th at if you own or operate an existing source subject to a work practice or management practice standard of a tune

- up, you must comply with this final rule no later than [ INSERT THE DATE 1 YEAR AFTER THE DATE OF
PUBLICATION IN THE FEDERAL REGISTER ]. If you own or operate an existing source subject to an emission limit or an energy assessment requirement, you must comply with this final rule no later than [ INSERT THE DATE 3 YEARS AFTER THE DATE OF
PUBLICATION IN THE FEDERAL REGISTER ]. As under the proposed

r ule, t he owner or operator of a new source is required to comply on [ INSERT THE DATE 60 DAYS AFTER THE DATE OF PUBLICATION
OF IN THE FEDERAL REGISTER ] or upon startup of th e facility, whichever is later. Additionally, we have clarified the compliance req uirements for commercial and industrial solid waste incineration units subject to 40 CFR part 60, subpart CCCC or subpart DDDD that

cease combusting solid waste and become subject to Subpart JJJJJJ. Owners and operators of commercial and industrial solid waste incineration units must be in compliance with this subpart on the effective date of the waste to fuel switch ( at least 12 months from the date that the owner or operator ceased**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **55** of **255** combusting solid waste ), if the effective date is after the applicable c ompliance date s discussed above

. W e have also re vised the proposed continuous compliance requirement and are no longer requiring CO CEMS for biomass, oil, and coal

- fired units to be consistent with changes to the emission limits in this final rule . For ne w and existing coal units with a heat input capacity greater than 10 MMBtu/h , we are requiring annual stack testing to demonstrate compliance with the CO emission limits. Because b oilers in the biomass and oil subcategories are only required to meet the m anagement practice standards in Table 2 of 40 CFR part 63, subpart JJJJJJ , no testing for CO emissions is required for these units.
G
. Affirmative Defense We have added provisions to this final rule to include an affirmative defense to civil penalties f or exceedances of emission limits that are caused by malfunctions. Consistent with Sierra Club v. EPA, EPA has established standards in this rule that apply at all times. However, i n response to an action to enforce the standards set forth in 40 CFR 63. 1 1201 , you may assert an affirmative defense for exceedances of such standards that are caused by malfunction, as defined at 40 CFR 63.2. ( See 40 CFR 63. 1122 6 (def ining “affirmative defense” to mean, in the**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **56** of **255** 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). The included provisions specify the elements tha t are necessary to establish an affirmative defense for periods of malfunction, including evidence and notification requirements that must be prepared by the source.
H. Technical/Editorial Corrections In this final action, we are making a number of techni cal corrections and clarifications to subpart JJJJJJ . These changes improve the clarity and procedures for implementing the emission limitations to affected sources. We are also clarifying several definitions to help affected sources determine their appl icability. We have modified some of the regulatory language that we proposed based on public comments. We made several changes to the initial compliance demonstration requirements. We revised 40 CFR 63. 11211 (a) to clarify that sources using a second fuel only for start up, shutdown, and/or transient flame stability are still considered to be sources using a single fuel. We deleted 40 CFR 63. 11210 ( b ) to remove the requirement that boilers with a heat**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **57** of **255** input capacity above 10 0 MMBtu /h are required to demons trate compliance by conduct ing a performance evaluation of their CO
CEMS
. We made a change to the monitoring requirements in 40 CFR 63. 11225 ( 40 CFR 63.11224 in the proposed rule) . We deleted paragraph ( e ) to remove the requirement that boilers having a heat input capacity of 100 MMBtu/h and subject to a CO limit to install a CO CEMS In response to comments asking for clarification, we have added definitions to 40 CFR 63. 11237 for “ Annual heat input basis ,” “ Energy use system ,” “ Hot water heater ,” “Mini mum scrubber pressure drop,” “Minimum voltage or amperage,” “Qualified energy assessor,” and “ Solid fossil fuel .” We have also revised several definitions in that section based on public comments. For example, we revised the definition of “boiler” to des cribe what is meant by the term “controlled flame combustion” as used in that definition. Several of the definitions in 40 CFR 64. 11237 were revised to clarify the types of equipment to which different standards apply. For example, the definition of “Wast e heat boiler” was revised to remove the criteria that 50 percent of total rated heat input capacity had to be from waste gases. We also revised**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **58** of **255** the definition of “Natural gas” to include gas derived from naturally occurring mixtures found in geological f ormations as long as the principal constituent is methane, consistent with the definition provided in 40 CFR part 60 subpart Db. A definition of propane, was also incorporated into the definition of natural gas.
**V .**  **Significant Area Source Public Comments**  **and Rationale for Changes to Proposed Rule**  This section contains a brief summary of major comments and responses. EPA received many comments on this subpart covering numerous topics. EPA’s responses to all comments, including those below, can be found i n the comment response document for Area Source Industrial, Commercial, and Institutional Boilers in the docket

. A. Legal and Applicability Issues Section 112( c ) (6) of the CAA
Comment: Some commenter s stated that EPA misinterpreted the statute in using M ACT instead of GACT for area sources. These commenters argued that the statute allows for setting a standard under CAA section 112(d)(2) that can be satisfied using the alternative GACT procedure specified in CAA section 112(d)(5) to meet the 112(c)(6) re quirement s .**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **59** of **255** Response: We disagree with the comment that the CAA gives EPA discretion to promulgate GACT standards pursuant to section 112(d)(5) for area source categories required to be regulated under section 112(c)(6). Section 112(c)(6) of the CAA
exp licitly requires that “sources accounting for not less than 90 per centum of the aggregate emissions of each [pollutant specified in this provision] are subject to standards under subsection 112(d)(2) or (d)(4)....” (Emphasis added). The plain language of s ection 112(c)(6) requires that the Agency set standards under section 112(d)(2) or (d)(4). There is no ambiguity in this language and thus the legislative history cited by the commenter is irrelevant. As such, the Agency is appropriately setting standard s for the sources at issue pursuant to section 112(d)(2). The commenter argues that section 112(d)(5) trumps the very specific language in section 112(c)(6). We disagree. Congress unambiguously required the Agency to set standards for these persistent, b ioaccumulative HAP under section 112(d)(2) or (d)(4). Had Congress wanted us to permit EPA to issue GACT standards for the 112 (c)(6) HAP, it would have said that EPA could issue standards under section 112(d), as it did in section 112(k)(3)(B) of the Act , noting that area sources shall be**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **60** of **255** subject to standards issued pursuant to “subsection (d) of this section.” Congress could not have been more precise in section 112(c)(6), and we reject the commenter’s interpretation. EPA has consistently maintained t hat standards under section 112(d)(2) or (d)(4) are required for the pollutants listed in section 112(c)(6). In this case, we are setting a section 112(d)(2) MACT standard for mercury and CO (as a surrogate for POM) for coal

- fired area source boilers , whi ch are the 112(c)(6) pollutant s that forms the basis for the listing of the source category at issue here.
Comment: One commenter argued that EPA did not provide justification for its decision that mercury and POM must be regulated pursuant to CAA section 112(c)(6) at area source boilers to satisfy the requirements that 90 percent of nationwide emissions of these pollutants must be reduced. The commenter further stated that the proposed rule and s upporting documentation provide no rationale basis or adequat e factual justification for the need to regulate area source POM or
mercury emissions to satisfy CAA section 112(c)(6). Specifically, the commenter stated that neither the proposed rule nor the MACT floor memo provide data that support the proposed determ ination that 90.3 percent of the 1990 emissions**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **61** of **255** inventory for mercury is already subject to regulation. In contrast, another commenter said that, once a category is listed under CAA section 112(c)(6), the only procedure available to EPA for refraining fro m promulgating a MACT

- based standard for the category is to remove the category from the CAA section 112(c) list through the use of CAA section 112(c)(9), regardless of whether the category is needed to meet the 90 percent requirement in CAA section 112(c) (6). Response: The statute does not limit EPA’s discretion as to how it fulfills its obligations under CAA section 112(c)(6). To the extent that the commenters seek to challenge whether EPA has selected appropriate categories to meet its obligations und er CAA section 112(c)(6) or whether EPA has met the requirement in CAA section 112(c)(6) to regulate categories emitting at least 90 percent of the specified pollutants (in this case, mercury and POM), such challenges should not be reviewed in the context of a review of an individual NESHAP. Rather, if review is appropriate, it should be in the context of an EPA finding that it has fulfilled its obligations under CAA section 112(c)(6), and an accounting by the agency of how it reached the 90 percent thresh old for each pollutant. Nevertheless, the docket for this rulemaking contains a**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **62** of **255** spreadsheet that demonstrates our belief that we have met the 90 percent requirement for POM and for mercury with this final rule. While we are promulgating GACT

- based provisi ons at this time for not only mercury but also POM from biomass

- fired and oil

- fired area source boilers, note that we have not removed or “delisted” oil

- fired and biomass

- fired area source boilers by this action. We simply are not promulgating MACT

- based regulations at this time because they are unnecessary to meet the requirements of CAA section 112(c)(6).
Comment: Comments received suggested EOM was not appropriate for representing POM emissions

. The commenters noted a drawback to using EOM as a surr ogate for POM is the limited amount of data available to quantify emissions, few EOM inventories or emission factors exist, and EOM includes other extractible organics in addition to the PAHs. The commenters suggest that the reasonable assumption is that any observed health effects come from the PAH faction and since EOM includes compounds other than PAH, it should not be used as a surrogate for POM. Response: This issue primarily affects whether biomass

fired and oil

- fired boilers are needed to meet th e CAA section**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **63** of **255** 112(c)(6) requirements. EPA has considered commenter input and revised the final rule based on our analysis of existing and new data submitted during the public comment period

. As we noted in the proposed rule, we reexamine the inventory as sociated with the original listing as we learn more about the source category in the rule development process. 75 FR 31904. Based on a re examination of the emission inventory in light of comments , we have determined that we only need ed to address the co al

- f ired portion of the area source segments of these categories under CAA section 112(c)(6) in order to meet the 90 percent threshold requirement of that provision for both mercury and POM.
As discussed in the preamble to the June 2010 proposed rule (75 FR 31896 ), we have determined that w e must regulate mercury and POM from coal

- fired area source boilers in order to meet the

r equirements in CAA section 112(c)(6), and we are establishing
MACT

- based limits for mercury and POM (using CO as a surrogate) for this subcategory

. We are implementing work practice standards, as allowed by CAA section 112(h), for control of mercury and POM from new and existing area source boilers in the coal subcategory with a designed heat input capacity less than 10 MMBtu/h.
I n the CAA section 112(c)(6) source listing, three**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **64** of **255** indicators (7

- PAH, 16

- PAH, and extractable organic matter ( EOM ) ) were used to represent POM emissions. While it was possible to attain the 90 percent threshold for 7

- PAH and 16

- PAH by promulgating MACT

- bas ed regulations only for coal

- fired area source boilers and without regulating biomass

- fired and oil

fired boilers under MACT, we believed at the time of proposal that we needed to promulgate MACT

- based limits for biomass

- fired and oil

- fired boilers in orde r to ensure that the 90 percent threshold for our third POM indicator, EOM, would be met. In our proposed rule, we used CO as a surrogate for all three indicators of POM because we believed low CO levels were indicators of good combustion, which was our m ethod of control for POM. The proposed CO limits were based on MACT because all types of area source boilers were, at that time, thought to be needed to meet our CAA section 112(c)(6) obligations for POM

. We have analyzed these comments and determined tha t EOM should not be used as one of the indicators for POM . We agree with the commenters who have identified data gaps in our knowledge of what source categories are emitting EOM. There are emissions estimates for 16

- PAH for many more categories than ther e are estimates for EOM. The use of 16

- PAH allows for the most accurate representation of the universe of categories that**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **65** of **255** emit POM and which are needed to meet our 90 percent requirement. The 16

- PAH inventory has emissions estimates for over four times a s many sources as EOM and three times as many
as 7

- PAH. While the relatively few estimates of 7

- PAH would suggest simply relying on 16

- PAH as an indicator for POM, both 7

- PAH and 16

- PAH include the compounds with the most well established links to adverse health effects. In contrast, EOM includes extractible organic matter that is not POM (in fact, most of it not POM). It is unclear whether the health effects of EOM are due to the PAH component captured by the other measures of POM or due to non

- POM compo unds. In short, we cannot say EOM is a good surrogate for the health effects of POM. In our judgment, t he lack of emission estimates for EOM creates a distorted picture of the relative contributions of source categories for which there are EOM estimates. The lack of source categories making up the total EOM inventory makes the relative contribution of the few categories that do have data unrealistically inflated. 1

1 When justifying its use in the 1998 invent ory, we said that EPA would undertak e an effort to develop a robust inventory for EOM sources to feed into the CAA section 112( c )( 6 ) inventory. Had more data been gathered, perhaps EOM would have proved to be a more useful indicator of POM. However, the anticipated We cannot say with confidence that by**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **66** of **255** using EOM as an indicator for POM that we are captur ing a significant percentage of either EOM emitted by all categories or POM emissions. We have analyzed these comments and determined that EOM should not be used as one of the indicators for POM. Therefore,

we re - examined the emission inventory u sing PA H (7

- PAH and 16

- PAH) as the indicator . Based on this re

- examination , regulating POM emissions from area source biomass and oil boilers are not needed to meet the CAA section 112(c)(6) obligations. Thus, POM emissions from area source boilers in the bioma ss and oil subcategories can be regulated under GACT, instead of MACT

. With respect to mercury and POM from area source boilers classified as biomass

- fired or oil

- fired, as well as with respect to other urban HAP besides POM, we have revised the final rul e standards t o reflect GACT for these two area source sub categories (see Section I V. B of this preamble)

. We are implementing management practice standards, as allowed by CAA section 112(d)(5), for control of POM from new and existing area source boilers i n the biomass and oil subcategories. The management practice standard for new and existing area source boilers requires the implementation of a tune

- up program.

inventory was not developed.**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **67** of **255** As stated previously in the preamble to the June 2010 proposed rule, we determined that the control technologies currently used by facilities in the source category to reduce

non - mercury metallic HAP and PM (multiclone, fabric filters, and ESP) are generally available and cost effective for new area source boilers. Additionally, these controls a re commonly required by s tate and other f ederal regulation s that apply to the area source boilers in the source categor y . Therefore, we are establishing numeric emission limits representing GACT for all new area source boilers with a heat input capacity g reater than 10 MMBtu/hr (using PM as a surrogate). Emission Standards for HAP Other than Mercury
Comment : One commenter stated that CAA section 112(c)(6) provides that EPA must “list categories and subcategories of sources assuring that sources accounti ng for not less than 90 percent of each [enumerated] pollutant are subject to standards under subsection (d)(2) or (d)(4) of this section.” The commenter also stated that the D.C. Circuit has held repeatedly that when EPA sets standards for a category or subcategory of sources under section 112(d)(2), EPA has a statutory duty to set emission standards for each HAP that the sources in that category or subcategory emit. The commenter concluded that when**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **68** of **255** EPA sets standards for area source boilers under secti on 112(d)(2), as section 112(c)(6) requires it to do, EPA must set section 112(d)(2) emission standards for all the HAP that area source boiler s emit. The commenter said that EPA appears to believe that because area source boiler s are needed only to reac h the section 112(c)(6) requirement of 90 percent for mercury and POM and not for the other pollutants enumerated in section 112(c)(6), EPA’s only obligation under section 112(c)(6) is to set section 112(d)(2) standards for mercury and POM . The commenter said that section 112(c)(6) expressly requires EPA to issue section 112(d)(2) standards for the “sources” in the categories listed under section 112(c)(6), not some subset of the pollutants that those sources emit, and that section 112(d)(2) standards must include emission standards for each HAP that a source category emits. The commenter continued by stating that nothing in the CAA exempts EPA from this requirement. The commenter concluded that, had Congress wished to give EPA discretion to set standards for only some of the pollutants emitted by a category listed under section 112(c)(6), it would have done so expressly. Response : EPA disagrees with the comment that, even though EPA lists a category under section 112(c)(6) due to the**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **69** of **255** emissions of one or more HAP specified in that section, EPA must issue emission standards for all HAP (including HAP not listed in section 112(c)(6)) that sources in that category emit. The commenter cited in support the opinion by the United States Court of Appeals for the D.C. Circuit in National Lime Ass’n v.

EPA , 233 F.3d 625, 633

- 634 (D.C. Cir. 2000)). The part of the National Lime opinion referenced in the comment dealt with EPA’s failure to set emission standards for certain HAP emitted by major sources of cement manu facturing because the Agency found no sources using control technologies for those HAP. In rejecting EPA’s argument, the court stated that EPA has “a statutory obligation to set emission standards for each listed
HAP.” Id. at 634. The Court noted the li st of HAP in section 112(b) and stated that section 112(d)(1) requires that EPA “promulgate regulations establishing emission standards for each category or subcategory of major sources ... of hazardous air pollutants listed for regulation ..” Id. (Emphasi s added). For the reasons stated below, we do not believe that today’s final rule is controlled by or otherwise conflicts with the National Lime decision. National Lime did not involve section 112(c)(6). That provision is ambiguous as to whether standar ds for listed source**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **70** of **255** categories must address all HAP or only the section 112(c)(6) HAP for which the source category was listed. Section 112 (c)(6) requires that “sources accounting for not less than 90 per centum of the aggregate emissions of each such [ specific] pollutant are subject to standards under subsection (d)(2) or (d)(4).” This language can reasonably be read to mean standards for the section 112(c)(6) HAP or standards for all HAP emitted by the source. Under either reading, the source would b e subject to a section 112(d)(2) or (d)(4) standard. The commenter insists that once a section 112(d)(2) standard comes into play, all HAP must be controlled (per National Lime ). But this result is not compelled by the pertinent provision, section 112(c)(6 ). That provision is obviously intended to ensure controls for specific persistent, bioaccumulative HAP, and this purpose is served by a reading which compels regulation under section 112(d)(2) only of the HAP for which a source category is listed under s ection 112(c)(6), rather than for all HAP. The facts here support the reasonableness of EPA’s approach. Area source boilers are included in source categor ies listed under section 112(c)(6) for regulation under section 112(d)(2) solely due to its mercu ry and POM emissions. There is**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **71** of **255** special statutory sensitivity to regulation of area source categories in section 112. For example, an area source category may be listed for regulation under section 112 if EPA makes an adverse effects finding pursuant to S ection 112(c)(3) or if EPA determines that the area source category is needed to meet its section 112(c)(3) obligations to regulate urban HAP or its section 112(c)(6) obligations to regulate certain persistent bioaccumulative HAP. Moreover, to the extent EPA lists an area source category pursuant to section 112(c)(3) (whether that finding is based on adverse effects to human health or the environment or a finding that the source is needed to meet the 90 percent requirement in section 112(c)(3), the statute gives EPA discretion to set GACT standards for such sources. 42 U.S.C. 7412(d)(5). EPA does not interpret section 112 (c)(6) to create a means of automatically compelling regulation of all HAP emitted by area sources unrelated to the core object of sec tion 112(c)(6), which is control of the specific persistent, bioaccumulative HAP, and thereby bypassing these otherwise applicable preconditions to setting section 112(d) standards for area sources. Nor does National Lime address the issue, since the

case dealt exclusively with major sources. 233 F. 3d at 633.**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **72** of **255** Consequently, EPA disagrees with the comment that it is compelled to promulgate section 112(d)(2) MACT standards for all HAP emitted by area source boiler s.

We are promulg ating the proposed standard requiring the performance of an energy assessment for existing area source facilities having an affected boiler with a designed heat input capacity of 10 MMBtu/h or greater. This final rule requires the performance of an energy assessment, by qualified personnel, on the boiler and its energy use systems to identify cost

- effective energy conservation measures. As discussed in the June 2010 proposed rule, a n energy assessment provides valuable information on improving energy effi ciency. Owners and operators are encouraged, but not required, to use the results of the energy assessment to increase the energy

- efficiency and
cost

- eff iciency of their boiler system. Beyond

- the

- floor option

In the proposed rule, the energy assessment requirement was a beyond

- the

- floor option for the MACT

- based mercury and CO emission standards because additional emission reductions would be realized as the results of these energy assessments. In this final rule , the energy assessment requirement is both a beyond

the

- floor con trol for the MACT

- based standards for the coal**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **73** of **255** subcategory and a GACT for the biomass and oil subcategory because energy assessment s are generally available and have already been performed at numerous facilities. The principle arguments against an energy assessment requirement are: 1) EPA lacks authority to impose requirements on portions of the source that are not designated as part of the affected source, such as non

- emitting energy using systems at a facility; 2) EPA has not quantified the reductions a ssociated with the energy assessment requirement, therefore it cannot be "beyond the floor;" and 3) the bare requirement to perform an audit without being required to implement its findings is not a standard under CAA section 112(d). With respect to the first argument, we have carefully limited the requirement to perform an energy audit to specific portions of the source that directly affect emissions from the affected source. The emissions that are being controlled come from the affected source. For co al

- fi r ed units, the process changes resulting from a change in an energy using system will reduce the volume of emissions at the affected source. For biomass

- fired and oil

- fired area sources, better management practices at energy using systems will reduce the emissions of HAP from the affected source by reducing fuel consumption and**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **74** of **255** the HAP released through combustion of fuel. In either case, the requirement controls the emissions of the affected source. With respect to the second argument, the energy a ssessment will generate emission reductions through the reduction in fuel use beyond those required by the floor. While the precise quantity of emission reductions will vary from source to source and cannot be precisely estimated, the requirement is clearl y directionally sound and thus consistent with the requirement to examine beyond the floor controls. By definition, any emission reduction would be cost effective or else it would not be implemented. Finally, with respect to the third argument, the
requ irement to perform the energy audit is, of course, a requirement that can be enforced and thus a standard. As noted, while we do not know the precise reductions that will occur at individual sources, the record indicates that energy assessments reduce fue l consumption and that parties will implement recommendations from an auditor that they believe are prudent. Therefore, the requirement to perform an energy assessment can both be enforced and will result in emission reductions.

Comment: Commenters stated that setting work practice Section 112(h) of the CAA**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **75** of **255** standards in lieu of emission standards f or area source boilers with a heat input capacity less than 10 MMBtu /h is unlawful and arbitrary. Commenters cited EPA’ s determination with respect to the techn ical and economic limitations on the enforcement of emission standards for boilers with heat input capacity less than 10 MMBtu /h , and stated that these limitations do not satisfy CAA s ection 112(h) conditions for setting work practice standards in lieu of emission standards. Some commenters argued that the technical limitations of measuring PM using Method 5, as discussed in the preamble to the proposed June 2010 rule, do
not a pply to mercury and CO. Other commenters remarked that the absence of sampling ports and stacks at area source boilers does not provide a basis for a technical or economic limitation, stating that sources are able to work around this issue. Multiple commenters said that the lack of measuring ports (which can affect retrofitting new boiler installations into existing buildings), other design requirements for efficient exhaust from smaller boilers, and the inapplicability of approved test methods would make measurement technically and economically impractical for both existing and new sources. Commenters specifically cited CAA s ection 112(h)(1) and (2), which allows the agency to prescribe work practice standards only if it is**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **76** of **255** “not feasible to prescribe or enforce an emission standard.... due to technological or economic limitations

. ” Response: EPA disagrees with commenters. As discussed in the preamble to the June 2010 proposed rule, CAA section 112(h) authorizes the Administrator to promulgate “a design, equipment, work practice, or operational standard, or combination thereof , ”

c onsistent 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 prescribe or enforce an emission standard. CAA section 112(h)(2)(B) further defines the term “not feasible” to

m ean when “the application of measurement technology to a particular class of sources is not practicable due to technological and economic limitations.” We have elected to implement work practice standards for coal

- fired boilers with a heat input capacity of less than 10 MMBtu/h because we have determined that the standard reference methods for measuring emissions of mercury, CO (as a surrogate for POM), and PM (as a surrogate for urban non

- mercury metals) are not applicable for sampling small diameter (les s than 12 inches) stacks. Furthermore, through the comment process, we have learned that common, very small boilers (less than 5 MMBtu/h) typically exhaust through vents and not stacks, and that the instillation**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **77** of **255** of ports into small diameter stacks for sma ller boilers would likely interfere with the functionality of exhaust systems for new and existing boilers. Because many existing area source boilers with a capacity below 10 MMBtu/h generally have stacks with diameters less than 12 inches, and because ma ny area source boilers do not currently have sampling ports or a platform for accessing the exhaust stack, we have determined that the testing and monitoring costs that area source boiler facilities would incur to demonstrate compliance with the proposed e mission limits would present an excessive burden for smaller sources. Thus, we are establishing work practice standards to limit the emissions of mercury and CO (as a surrogate for POM) for existing and new coal

- fired area source boilers having a heat inp ut capacity of less than 10 MMBTU/h

. De minim i s Levels
Comment: Several commenters stated that EPA should establish a de minim i s heat input level (less than 1 MMBtu/h heat input capacity) below which area sources are not subject to regulation or only subj ect to work practice standards. These commenters referenced water heaters and small comfort heating units that are not used in industrial, commercial, or institutional process es but instead used to provide hot water**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **78** of **255** for personal use or seasonal comfort he ating. Other commenters noted that State rules that require work practice requirements for boilers all have a lower limit on applicability of typically 1 to 5 MMBtu/hr; these commenters stated that EPA has provided no basis for applying work practice stan dards to boilers of this size. Response: EPA must establish standards for each category or subcategory of major sources and area sources of HAP listed pursuant to CAA section 112(c). EPA may distinguish among classes, types, and size in establishing such standards but the standards established must be applicable to new and existing sources of HAP within the category. However, we agree with the
commenters that the categories of boiler covered by this rule are industrial boilers, commercial boilers, and in stitutional boilers. In the proposed rule, we did not list hot water heaters as exempted as we did in the proposed Boiler MACT for major sources. As stated in the preamble to the proposed Boiler MACT, hot water heaters meet the definition of a boiler but are more appropriately described as residential

- type boilers, not industrial, commercial, or institutional boilers because their output is intended for personal use rather than for use in an industrial, commercial, or institutional process. The primary**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **79** of **255**

r eason for exempting hot water heaters in the Boiler MACT was that hot water heaters are not part of the listed source category. Because hot water heaters generally use natural gas and gas

- fired boilers were not part of the area source category, we did not include a similar exemption in the proposed rule. To be consistent with the Boiler MACT , we have included in this final rule a similar exemption and definition for hot water heaters.
B. CO Limits
Comment: Mult iple commenters argued that EPA’ s determin ation of using CO as a surrogate for POM is inappropriate

. Several of these commenters reiterated that there is no reliable correlation between CO and POM. Some

co mmenter s stated that CO is not an appropriate surrogate for POM or organic HAP at lower CO emission levels

. For instance, one commenter stated that while there is a linear correlation between decreasing CO and decreasing HAP at higher levels, once CO values fall under 100 ppm, further reduction of CO d oes not provide any substantial correlating reduction of HAP. Other commenters stated that CO is an inadequate surrogate for POM because there is no POM invariably present in CO; likewise, commenters stated that because CO and POM have different**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **80** of **255** mechanisms of formation and reduction , CO cannot be considered as a reliable surrogate. Several commenters suggested total hydrocarbon ( THC ) a s a better surrogate , stating that THC levels are often more stable and less reactive to load swings than CO

. Commenters noted that
THC has been used as a surrogat e for organic HAP emissions in other regulatory efforts, including the hazardous waste incinerator MACT

. Response: EPA acknowledges commenters’ concerns. Based on new data received during the public comment period, we have re

examined our analysis and re vised the final standards for CO. As previously discussed, this final rule only establishes CO emission limits for coal

- fired boilers pursuant to CAA section 112(c)(6). We are implementing management practice standards, as allowed by CAA section 112(d)(5 ), for control of CO from new and existing area source boilers in the biomass and oil subcategories. Additionally, for the coal subcategory, we have revised the final CO emission limits to ensure a more accurate correlation between POM and CO levels. EPA is aware of one European study that finds the correlation between CO and POM (or organic HAP, in general) is weaker at lower CO concentrations (less than 100 ppmv) but we did not have the opportunity to**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **81** of **255** examine the data relied on by the study and no data supporting this supposition were submitted as part of the public comments

. We have revised the final standards ( 400 ppm ) based on 99.9 percent UPL as discussed in Section I V.C of this preamble

. EPA believes that CO is a reliable surrogate for POM at this emission level. EPA considered using THC as a surrogate for POM, however, we did not have available THC data for area

sources. Comment: Several commenters expressed concern with respect to the proposed CO limits. Some commenters stated that the
prop osed CO limits are unachievable for some units, including liquid

- fired boilers. Commenters further stated that meeting the CO limits would be more burdensome for area sources than major sources. Specifically, many commenters argued that the CO limits are unfeasible from a measurement, operability, and cost standpoint , particularly when considered simultaneously with other limits (NO x , VOC). Some commenters expressed concern that prioritizing CO reduction may promote boiler inefficiency and result in high er emissions of NO x . Other commenters suggested that the CO emission limits should be determined using long

- term CEMS data to account for natural variability in CO emissions . Commenters also offered**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **82** of **255** alternatives for control of POM. One commenter sugges ted that EPA consider cleaner fuels or end of stack technologies for control, such as fabric filters and scrubbers that capture POM and POM

- precursors . Response: As discussed above, this final rule establishes
MACT

- based emission limits for CO only for new and existing coal

- fired boilers. In this final rule , a rea source boilers in the biomass and oil

- fired subcategories are no t required to meet CO emission limits; these boilers are instead required to meet the management practice standard which consists of a tune

- up. The MACT

- based CO emission limits are still required for coal

fired area source boilers in order to meet our obligation under CAA section 112(c)(6)

. Based on the available CO data and the revised UPL calculation methodology , the final C O e mission limits for coal

- fired area source boilers are higher than the proposed limits which should provide more assurance that the limit can be achieved at all times. EPA notes that the available dataset did not include sufficient long

- term CEMS data for area sources to be used to set a limit . Therefore, we have established the CO standards based on the data provided using the revised UPL methodology to account for variability over the operating cycle of typical industrial, commercial, and**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **83** of **255** institutional b oilers

. We also considered other appropriate control options for sources in each subcategory, including switching to clean fuels and end of stack technologies

. We considered whether fuel switching could be technically achieved by boilers in the subcatego ry considering the existing design of boil ers and the availability of various types of fuel. W e determined that fuel switching was not an appropriate control technology based on the overall effect of fuel switching on HAP emissions and the technical and d esign considerations discussed previously in th e preamble to the proposed June 2010 rule (75 FR 31896)
. This determination is discussed in the memorandum

“ Development of Fuel Switching Costs and Emission Reductions for Industrial, Commercial, and Institut ional Boilers and Process Heaters National Emission Standards for Hazardous Air Pollutants

– Area Source ” located in the docket. Additionally, EPA did not identify add

- on control technologies available for control of CO in use at area source boilers.
C. MACT Floor Analysis Pollutant

- by

- pollutant approach
Comment: Several commenters argued that the pollutant

- by

pollutant approach used by EPA is not appropriate. Commenters rejected the pollutant

- by

- pollutant approach on the basis that**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **84** of **255** both PM and CO em ission limits are not achievable even for the best performing sources. These commenters argued that because the proposed area source MACT standards rely on a different set of best performing sources for each separate HAP standard, no single source is in t he population of units for both the PM and CO emission limits, and therefore, the approach does not reflect the performance of the best performing boilers. Rather, commenters asserted that the proposed limits were unrealistic, unnecessarily stringent, and unachievable. Commenters further stated that the provisions of CAA sections 112(d)(1), (2), and (3) of the CAA require that standards must be based on actual sources, and cannot be the product of pollutant

- by

- pollutant "cherry

- picking

. " C ommenters state d that EPA does not have the authority to “distinguish” units and sources by individual pollutant. Other commenters stated that EPA must set limits for each HAP that the sources in the subcategory emit, and not solely mercury or POM. These commenters sta ted that to ignore the emitted HAP violates the CAA and the court order. Response: EPA is mindful that MACT floors mu st reflect achieved performance. EPA is also mindful that that costs cannot be considered by EPA in ascertaining the level of the
MACT floor. See, e.g., Brick MACT , 479 F. 3d at 880

– 81, 882

– 83;**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **85** of **255** NRDC v. EPA , 489 F. 3d 1364, 1376 (DC Cir. 2007) ( “ Plywood
MACT ” ); see also Cement Kiln Recycling Coalition v. EPA , 255 F. 3d 855, 861

– 62 (DC Cir. 2001) ( “ achievability ” requirement of
CAA section 112(d)(2) cannot override the requirement that floors be calculated on the basis of what best performers actually achieved). EPA has carefully developed data for each standard, assessing both technological controls and HAP inputs in doing

so. The MACT floor variability methodology is discussed in a later response. Among all boilers at area sources, only new and existing coal

- fired ones will need to meet MACT

- based limits. Nevertheless, i t is true that at least some coal

- fired area source boilers will n eed to install controls to meet these standards, and that these controls have significant costs. This is part of the expected MACT process where, by definition, the averaged performance of the very best performers sets the minimum level of the standard. The Agency believes that it has followed the statute and applicable case law in developing its floor methodology. Although i ndustry commenters maintain these

sources can not meet the standards , which are predicated on their

own perf ormance without adding c ontrols, t his contention lacks a**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **86** of **255** basis in the record. For mercury, 6 of the 7 boilers for which EPA has emissions data are meeting the MACT floor standards for
mercury . For CO , 13 of the 16 boilers in the MACT pool meet the promulgated standard

. In thos e instances where commenters provided actual data on these plants’ performance, EPA took the information into account in developing the final standards. Indeed, EPA adjusted all of the standards based on actual data presented. We have emissions data on a limited number of area source units. The available information does indicate that at least one unit meets both the final PM and CO emission limits

. Dataset for the MACT Floor Analysis
Comment: Commenters stated numerous objections to the dataset used for the MACT floor analysis. Some commenters stated that it is inappropriate to apply limits from data submitted as part of the major source industrial boiler MACT ICR to area sources. Commenters objected to EPA's assertion that boilers at area sources a re similar in size and operation to major source boilers; one commenter noted that EPA did not use test data from area source facilities to set major source floors. Other commenters stated that the emission limits are significantly flawed because they ar e based on inadequate data**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **87** of **255** and not representative of the units in the source category. These commenters stated that the data collected is insufficient because it represents the performance of less than 1 percent of almost 183,000 existing area source boil ers, particularly given that EPA based the analysis on the top 12 percent of units for which data were available. Commenters further stated that there was insufficient data available to establish appropriate boiler

type subcategories.
Some commenters ex pressed that EPA must include emissions data collected by State and local permitting authorities in establishing the MACT floor; these commenters stated that th ese data are more objective than the newer industry testing and are also necessary to fill in "g aps" in the existing data. Other commenters requested that certain data should be excluded from the MACT floor analysis. For instance, some commenters stated that non

- detect data should be excluded or that the analysis should be adjusted to account for t he capabilities of the test methods. These commenters stated that the non

- detect data results in an unreasonably low MACT floor ; some commenters stated that the proposed limits are in some cases below the detection capability of the required test method

. Commenters also stated that EPA has not justified using three times the**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **88** of **2 55**  detection level in its analysis. These commenters stated that this method biases the results towards higher HAP emissions, results in a hypothetical standard that is unrealistic and not determined as required by statute. Response: EPA acknowledges commenters' concerns. As mentioned elsewhere in this preamble, EPA is required to establish MACT floor levels using existing emissions information. For all data sets, the final emission l imits are based on the available data and EPA’s assessment of variability. Since proposal we have received updated data on certain boilers and used that data to revise our emission estimates from the best performing sources. We re - evaluated the informati on available for the area source category and revised the proposed
MACT

- based CO emission limits such that they only apply to boilers in the coal sub category. As discussed above, based on information received during the public comment period, we determine d that regulating POM emissions from area source biomass and oil boilers is not needed to meet our CAA section 112(c)(6) obligations ; we only need to regulate coal

- fired area source boilers under section 112(d)2) to meet the 90 percent requirement set fort h in CAA section 112(c)(6) for POM. The emissions limits for CO for coal

- fired boilers were based on the**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **89** of **255** available information from the ICR and state operating permits , as well as that received in comments. EPA disagrees with commenters who stated that we excluded emissions data collected by State and local permitting authorities in establishing the MACT floor

. The available S tate permits obtained for coal

- fired area source boilers limiting CO emissions were for 11 units located in Ohio (3 units), and Ill inois (8 units). We also obtained CO emission data from five coal

- fired area source boilers as part of the information collection effort for the major source NESHAP. Even though the latter data were gathered in the course of collecting data on major sour ces, the emission data on these five boilers is from emission sources in the area source coal

- fired boiler subcategory. With respect to non

- detect data, EPA considered and accounted for non

- detect data when conducting the MACT analysis for mercury for exis ting and new coal

- fired boilers in this final rule

. EPA developed a methodology to account for the imprecision introduced by incorporating non

- detect data into the MACT floor calculation. At very low emission levels where emissions tests result in non

- de tect values, the inherent imprecision in the pollutant measurement method has a large**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **90** of **255** influence on the reliability of the data underlying the MACT floor emission limit. Because of sample and emission matrix effects, laboratory techniques, sample size, and other factors, method detection levels normally vary from test to test for any specific test method and pollutant measurement. The confidence level that a value, measured at the detection level is greater than zero, is about 99 percent. The expected mea surement imprecision for an emissions value occurring at or near the method detection level is about 40 to 50 percent. Pollutant measurement imprecision decreases to a consistent level of 10 to 15 percent for values measured at a level about three times t he method detection level. 2 One approach that we believe can be applied to account for measurement variability in this situation starts with defining a method detection level that is representative of the data used in the data pool. The first step in this approach would be to identify the highest test

- specific method detection level reported in a data set that is also equal to or less than the average emission calculated for the data set. This approach has the advantage of relying on the data collected to develop the

2 American Society of Mechanical Engineers, Reference Method Accuracy and Precision (ReMAP): Phase 1, Precision of Manual Stack Emission Measurements , CRTD Vol. 60, February 2001.**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **91** of **255** MACT floor emission limit, while to some degree, minimizing the effect of a test(s) with an inordinately high method detection level (e.g., the sample volume was too small, the laboratory technique was insufficiently sensitive or the procedure for determining the detection level was other than that specified). The second step is t o determine the value equal to three times the representative method detection level and compare it to the calculated MACT floor emission limit. If three times the representative method detection level were less than the calculated MACT floor emission limit, we would conclude that measurement variability is adequately addressed, and we would not adjust the calculated MACT floor emission limit. If, on the other hand, the value equal to three times the representative method detection level were greater than the calculated MACT floor emission limit, we would conclude that the calculated MACT floor emission limit does not account entirely for measurement variability. T h erefore, we use d the value equal to 3 times the method detection level in place of the calculated MACT floor emission limit to ensure that the MACT floor emission limit for
mercury accounts for measurement variability and imprecision. Variability
Commen t: Numerous commenters stated that the floor**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **92** of **255** methodology used by EPA is unlawful. Some commenters criticized EPA's application of the UPL to all the test results for all sources in the top twelve percent. These commenters stated that while EPA can consi der variability in estimating an individual source's performance over time, it cannot account for differences in performance between sources. Specifically, these commenters stated that EPA may only account for differences in performance between sources ex cept as CAA s ection 112(d)(3) provides, by averaging the emission levels achieved by the sources in the top 12 percent. Commenters stated that the UPL is not equivalent to the "average" emission level. For instance, some commenters stated that the method ology for the mercury and CO emission limits for new coal fired units does not reflect the emission levels achieved by the single best performing source; these commenters stated that the proposed method result s in higher emission levels for new sources tha n the average level of the best 12 percent. Commenters further stated that EPA erred by relying on the 99 percent UPL only to reflect variability. Some commenters stated that EPA must collect and consider data on additional variability, such as that rela ted to variable fuel quality or longer term variability, to supplement its analysis. These**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **93** of **255** commenters stated that the short

- term test data are not representative of long

- term operation of a unit nor are they likely to reflect the “worst reasonably foresee able circumstances” a unit may experience . Other commenters stated that EPA should use the upper tolerance limit (UTL) in lieu of the UPL; these commenters claimed that the UTL is more appropriate for situations where the available data does not represent the entire population

. Response : EPA disagrees with commenters and believes that the final emission limits appropriately account for variability. The Court has recognized that EPA may consider variability in estimating the degree of emission reduction a chieved by the best

- performing sources and in setting MACT floors that the best performing sources can expect to meet “every day and under all operating conditions". See Mossville Env ironmenta l Action Now

v. EPA , 370 F.3d 1232, 1241

– 42 (D.C. Cir 2004). F urthermore,
CAA section 112(d)(3) includes a provision stating that the MACT floor for existing sources cannot be less stringent than “the average emission limitation achieved by the best

- performing 12 percent of the existing sources (for which the Adminis trator has emissions information).” We see no statutory prohibition in considering inter

- source variability of the best performing**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **94** of **255** sources (which is all our floor calculation does, by considering the pooled variability of the best performing sources). Se ction 112(d)(3) of the CAA does not specify any single method of ascertaining an average. Considering the average variability among the group of best performing sources is well within the language of the provision (and was upheld in Chemical Manufacturers Ass ociation v. EPA ; see 870 F. 2d at 228). The commenters' argument that "average" can only mean average of emission levels achieved in performance tests of an individual unit is inconsistent with the holding in Mossville , 370 F. 3d at 1242, that EPA mus t account for variability in developing MACT floors and that individual performance tests do not by themselves account for such variability. Therefore, we believe that it is reasonable and necessary to account for inter

- source variability of the best perf orming sources by taking the pooled average of the best performing sources' variability. This is an aspect of identifying the average performance of those sources. Furthermore, EPA is confident that the UPL is an appropriate statistical tool to use in d etermining variability when there is a limited sampling of the source category. EPA has considered comments regarding suggested al ternatives to the UPL statistic, such as the upper tolerance limit (UTL)

. Whereas**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **95** of **255** a confidence interval covers a population parameter with a stated confidence, that is, a certain proportion of the time, a tolerance interval cover s a fixed proportion of the population with a stated confidence. I.e., c onfidence limits are limits within which we expect a given population paramete r, such as the mean, to lie ; s tatistical tolerance limits are limits within which we expect a stated proportion of the population to lie. Given this definition, the 99 percent UTL represents the value which we can expect 99 percent of the measurements to fall below 99 percent of the time in repeated sampling. In other words, if we were to obtain another set of emission observations from the floor sources, we can be 99 percent confident that 99 percent of these measurements will fall below a specified leve l. Since you must calculate the sample percentile, and the sample sizes for the area source boiler floor data are small, the 99 th percentile is underestimated. The refore, EPA notes that the UTL should only be used where one can calculate a sample percent ile, e.g., where there is a sample size of at least 100. On the other hand, a prediction interval for a future observation is an interval that will, with a specified degree of confidence, contain the next (or some other pre

- specified) randomly selected ob servation from a population. In other words, the prediction**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **96** of **255** interval estimates what future values will be, based upon present or past background samples taken. T he UPL represents the value which we can expect the mean of 3 future observations (3

- run aver age) to fall below, based upon the results of the independent sample of size n from the same population. Given the above considerations , EPA notes that only the UPL adequately get s at the notion of average emissions for a small sample size

. EPA has revise d its default selection of data distributions consistent with its guidance document “ Data Quality Assessment: Statistical Methods for Practitioners EPA QA/G

- 9S ” . This document indicates that most environmental data is lognormally distributed, so EPA has modified its assumptions when the results of the skewness and kurtosis tests result in a tie, or when there is not enough data to complete the skewness and kurtosis tests. With respect to the methods used to compute the UPL for a dataset that is determine d to be lognormally distributed, EPA also considered the commenters suggested revisions to the calculations in order to avoid skewing the UPL by calculating the UPL of an arithmetic mean instead of the UPL of a geometric mean. To adjust the calculation EP A considered a scale bias correction approach as well as a new UPL equation based on a Bhaumik and Gibbons 2004 paper, which calculates “An**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **97** of **255** Upper Prediction Limit for the Arithmetic Mean of a Lognormal Random Variable 3

Additionally, EPA has determined that 99 percent UPL is appropriate for fuel based HAP, and a 99.9 percent UPL is appropriate for CO. For fuel

- ba sed HAP the 99 percent confidence level is consistent with other recent rulemakings 75 FR 54975. Further, as commenters have noted elsewhere , the sample sizes were limited and EPA determined that a level of 99 percent is a good compromise and represents e mission levels that are protective of human health and the environment. Given that the subcategories had limited data to establ ish the floor calculations, EPA determined it was inappropriate to use a confidence level lower than 99 percent. Further, for f uel based HAP mercury, EPA has implemented an additional fuel variability analysis. Additionally, there are well established control measures currently used on units in the source category (fabric filters for PM and mercury) that serve to mitigate, to som e degree, the variability in emissions that can be expected. ”. Given data availability, EPA selec ted the Bhaumik and Gibbons 2004 approach which addresses commenters concerns with the proposed computations.

3 Bhaumik, D. K. and R. D. Gibb ons. 2004. An Upper Prediction Limit for the Arithmetic Mean of a Lognormal Random Variable. May 1, 2004. Technometrics 46(2): 239

- 248. doi:10.1198/004017004000000284**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **98** of **255** Given th ese additional consideration s for fuel

- based HAP, but recognizing the emission limits must be met at all times yet are based on short term stack test data, EPA selected the 99 percent

co nfidence level. For CO, EPA considered both quantitative and qualitative comments received during the public comment period on how CO emissions vary with load, fuel mixes and other routine operating conditions. After considering these comments EPA determ ined that a 99.9 percent confidence level for CO would better account for some of these fluctuations. Finally, EPA notes that where appropriate, we have accounted for variable fuel quality. EPA first took fuel into consideration, among other boiler desig n factors when it divided the source category into subcategories. EPA is aware that differences between given types of units, and fuel, can affect technical feasibility of applying emission control techniques. As noted in the preamble to the June 2010 pr oposed rule, EPA attempted to assess the impact of fuel variability for development of the mercury standard. However, n o fuel analysis data from boilers in the top 12 percent were available for assessing the impact of fuel variability on mercury emissions

. EPA realizes that mercury is a fuel dependent HAP, and that the amount of mercury emitted from the boiler depends on the amount**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **99** of **255** of mercury contained in the fuel. For this final rule , we have implemented a fuel variability factor into the mercury emissi on limit by determining a factor relating the highest mercury content to the average mercury content in coal that may be used at sources comprising the best 12 percent of sources. We also note that fuel usage can be reduced by improving the combustion eff iciency of the boiler. Therefore, in the development of the final standards, we are establishing requirements for larger existing boilers (greater than 10 MMBtu/h heat input capacity) to conduct an energy assessment, and smaller boilers ( both existing and new boilers with a heat input capacity less than 10 MMBtu/h) to meet a work practice or management practice requirements of a tune

- up, in order to improve combustion efficiency.
D. Beyond the Floor Analysis
Comment: Several commenters objected to EPA's beyond

- the

floor determination for new area source boilers. Many of these
commenters stated that the beyond the floor approach must consider fuel switching as an option. Other commenters objected to EPA's beyond

- the

- floor determination for existing boile rs, specifically stating that EPA should require existing facilities to either comply with emission limits for larger units , or**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **100** of **255** require fuel switching to the cleanest fuel in their class (fuel type). Commenters noted that while EPA identified substantial emissions reductions for mercury and POM from switching coal

fired boilers to natural gas, EPA failed to rationalize why fuel

- switching is not a technically feasible or economically achievable option. Commenters debated EPA's stated concerns regarding fue l availability and curtailment, arguing that there is sufficient capacity to meet the expected increased demand for natural gas. Furthermore, these commenters stated that the potential increases in metallic HAP emissions from fuel

switching were minor and should be considered in light of overall reductions for POM. Response : EPA has considered this comment and concluded that fuel switching is not an appropriate option for the beyond the floor level of control. EPA originally considered whether fuel swi tching would be an appropriate control option for sources in each subcategory under the proposed rule, including the feasibility of fuel switching to other fuels used in the subcategory and to fuels from other subcategories. This consideration included de termining whether switching fuels would achieve lower HAP emissions. We also gave consideration to whether fuel switching could be technically achieved by boilers**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **101** of **255** in the subcategory considering the existing design of boil ers and the availability of variou s types of fuel. After considering these factors, we determined that fuel switching was
not an appropriate control technology for purposes of determining the MACT floor level or beyond the floor level of control for any subcategory. This decision i s base d on the overall effect of fuel switching on HAP emissions, technical and design considerations discussed previously in th e preamble to the proposed June 2010 rule (75 FR 31896) , and concerns about fuel availability. This determination is discussed in the memorandum “ Development of Fuel Switching Costs and Emission Reductions for Industrial, Commercial, and Institutional Boilers and Process Heaters National Emission Standards for Hazardous Air Pollutants

– Area Source ” located in the docket. Energy Asse ssments
Comment: Several commenters disagreed with EPA's determination to require energy assessments as a beyond the floor option

. Commenters specifically stated that EPA cannot require an energy assessment because an assessment is not an emission standa rd and there is no proven relationship between HAP emissions and the assessment. Other commenters argued that the proposed requirements for an energy assessment were not**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **102** of **255** stringent enough; these commenters stated that a n energy
assessment cannot impose sta ndards more stringent than the MACT floor. For instance, one commenter argued that if EPA did not require implementation of the energy assessment findings, no reductions in fuel use or HAP would result. The commenter further asserted that even an impleme nted energy assessment

w ould not reduce HAP emissions consistent with the requirements of CAA s ection 112(d)(2). One commenter specifically stated that by only considering energy audits, EPA did not consider the full range of potential emission measures. Other commenters argued that EPA does not have the authority to require a n energy assessment , and that the proposed requirements were "too broad" or "too intrusive

. " Commenters were concerned that the energy assessment would include not only than the affe cted source, but also the entire facility, which EPA does not have the authority to regulate. Response: EPA disagrees with commenters that state that EPA does not have the authority to require an energy assessment.

A n ener gy assessment is an appropria te beyond

- the

- floor control technology because it is one of the measures identified in CAA section 112(d)(2). CAA section 112(d)(2) states that “Emission standards promulgated ... and applicable to new or existing**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **103** of **255** sources ... is achievable ... through app lication of measures, processes, methods, systems or techniques including, but not limited to measures which

– (A) reduce the volume of, or eliminate emissions of, such pollutants through process changes, substitution of materials or other modifications,

. . . (D) are design, equipment, work practice, or operational standards (including requirements for operator training or certification) as provided in subsection (h), or (E) are a combination of the above. " The purpose of an energy assessment is to identify energy

con servation measures (such as, process changes or other modifications to the facility) that can be implemented to reduce the facility energy demand which would result in reduced fuel use. Reduced fuel use will result in a corresponding reduction in HAP, and non - HAP, emissions. Thus, an energy assessment, in combination with the MACT emission limits will result in the maximum degree of reduction in emissions as required by CAA section 112(d)(2). It is not EPA's intent to require an energy assessment for**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **104** of **255** th e entire facility ; the energy assessment is only applied to existing boilers and their energy use systems located at area

sources . EPA acknowledges that the proposed definition for "energy assessment" is unclear, and w e have revised this final rule to cla rify the definition with respect to the requirements of Table 3 of subpart JJJJJJ (see 40 CFR 63.11237 )
. In order to account for variability among boiler systems and energy use systems and to ensure that affected sources can adequately comply with the req uirements, we have distinguished the requirements for the energy assessment based on the heat input use of the affect ed source

. We have also added a definition for

" energy use systems" to clarify the components for each boiler system and energy use system which must be considered during the energy assessment, including elements such as combustion management, thermal energy recovery, energy resource selection, and the steam end

- use management of each affected boiler. These revisions clarify that an energy assessment is only required for those portions of the facility using steam energy from the affected boiler system. Additionally, a facility may elect, but is not required, to implement the cost

- effective energy conservation measures identified in the energ y assessment. Because we lack**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **105** of **255** information on whether implementation of the conservation measures will prove cost

- effective or economically feasible for facilities, we are allowing t he owner or operator to determine the implementation of energy conservatio n measures identified in the energy assessment. EPA notes that t he cost of an energy assessment is minimal, in most cases, compared to the cost for testing and monitoring to demonstrate compliance with an emission limit. Furthermore, the costs of any ene rgy conservation improvement for the owner or operator will be offset , at least in part, by the cost savings in lower fuel costs. Therefore, after considering the structure of the requirement, the incentives it presents, and the likely behavior of sources , it is our judgment that sources will find it cost

effective to implement the conservation measures identified in the energy assessment , and we ha ve elected to promulgate requirements for an energy assessment for all existing boilers with a heat input cap acity greater than 10 MMBtu/h as a beyond the floor option or GACT
. EPA disagrees with commenters that state that the option for an energy assessment included in the June 2010 proposed rule is
not stringent enough. An energy assessment refers to a proces s which involves a thorough examination of potential savings from**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **106** of **255** energy efficiency improvements, pollution prevention, and productivity improvement. It leads to the reduction of

p ollutants through process changes and other efficiency modifications. I mpr oving energy efficiency reduces negative impacts on the environment as well as operating and maintenance costs; i mprovement s in energy efficiency result in decreased fuel use which results in a corresponding decrease in emissions (both HAP and non

- HAP) fro m the boiler

. The revised definition s of " energy assessment " and " energy use system s , " as discussed above, h a ve been expanded to include the specific components that must be considered for an energy assessment. These changes elucidate the in

- depth nature of the energy assessment, which requires identifying all energy conservation measures appropriate for a facility g iven its operating parameters.

EPA proposed the energy assessment as a beyond the floor option for existing area source boilers having a hea t input capacity of greater than 10 MMBTU/h , rather than focusing on smaller boilers

. We also examined other emission measures currently in place. EPA did not have sufficient information to determine if requiring an energy assessment for area boilers wit h a heat input capacity of less than 10 MMBtu/h is economically feasible. For boilers with a heat input capacity**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **107** of **255** less than 10 MMBtu/h, the data that we have suggests that area source boilers typically conduct boiler tune

- ups. We also examined work practi ces listed in State regulations for area source boilers with a heat input capacity less than 10 MMBtu/h

. These regulations included tune

- ups ( 10 States), operator training (one State), periodic inspections (two States), and operation in accordance wit h ma nufacturer specifications (one State). When energy assessments have been undertaken in the past, they typically result in 10 to 15 percent reduction in fuel use, according to the Department of Energy who has conducted energy assessment at selected manufact uring facilities. While the efficiency gains may be somewhat less when the assessment is mandated for a source rather than voluntary, the absence of a requirement to implement the particular findings of the assessment should still result in measures being implemented that are cost

- effective for the source and in emission reductions over and above what is otherwise required by MACT and other GACT measures. Therefore, we elected to promulgate requirements for an energy assessment for all existing boilers wi th a heat input capacity greater than 10 MMBtu/h, and requir e area source boilers in the biomass and oil subcategories with a**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **108** of **255** heat input capacity of greater than 10 MMBtu/h to meet the management practice standard of a tune

- up. These requirements
represen t the generally available and cost

- effective pollution reduction measures that are already required or in place.
E. GACT Standards
Comment: Commenters stated that the GACT standards should consist of work practice standards, rather than numeric emission limits. One commenter specifically stated that i n order to reduce the burden on small facilities operating boilers, EPA should establish work practice standard s for CO instead of emission limits , referencing requirements from the state of New Jersey . Ot her commenters stated that t he emission limits and testing procedures proposed for new boilers impose onerous capital and annual costs on potential project owners , which typically include schools, small businesses, hospitals, and other institutions in ru ra l areas. Some commenters stated that the CO emission limits were not achievable for small boilers over a range of operating periods, and that EPA should consider work practice standards in order to account for load variability. Response : EPA has consider ed commenter's concerns. CAA section 112(d)(5) allows the Administrator, with respect to area**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **109** of **255** sources, to promulgate standards which provide for the use of generally available control technologies or management practices to reduce emissions of HAP . There fore, w ith respect to mercury and POM from area source boilers classified as biomass

- fired or oil

- fired, as well as with respect to other urban HAP besides POM, we have developed standards that reflect GACT for t hese two area source categories.
W hile t he June 2010 proposed rule (75 FR 31896) set numeric MACT standards for CO (as a surrogate pollutant for the individual urban organic HAP) and merc ury, and numeric GACT emission limits for PM (as a surrogate for the individual urban metal HAP) , E PA has revis ed the standards for area source boilers classified in the biomass and oil subcategories

. Rather than require a numeric MACT emission limit for POM , new and existing area source boilers in the biomass or oil subcategories
must meet the r equirements of GAC T, which are management practice standards as described in Table 2 of 40 CFR part 63, subpart JJJJJJ

. However, f or the purposes of regulating PM from new area source boilers , EPA has determined that the GACT standards should consist of numeric emission lim its. P M is used a s a surrogate for urban metals , which we are required to regulate**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **110** of **255** pursuant to CAA s ection 112 c )(6)
. The dat a that we have available suggests that the control technologies currently used by facilities in the source category for reduction of non

mercury metallic HAP and PM are multiclones, which are generally used at area sources using solid fuel . We previously determined during the development of the June 2010 proposed rule that these controls are generally available and cost effective fo r new area source boilers. Additionally, we noted that new area source boilers with heat input capacity of 30 MMBtu/h or greater are subject to the NSPS for boilers (either subpart Db or Dc of 40 CFR part 60) , which regulate emissions of PM and require
pe rformance testing. Furthermore, new coal

- fired area source boilers with heat input capacity of 10 MMBtu/h or greater will likely require a PM control device to comply with the proposed mercury MACT standard and required performance testing

. Therefore, a numerical limit for PM consistent with the devices required to meet mercury MACT should be generally achievable. EPA has also revised the PM emission limits for area source boilers with a heat input capacity between 10 and 30 MMBtu/h; these limits have bee n revised to reflect the performance of GACT, which are multiclones. The PM GACT limits were calculated as the average of the data from units using GACT technology.**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **111** of **255** EPA has determined that the promulgated numeric emission limits for PM are appropriate GA CT standards for new area source boilers with a heat input capacity greater than 10 MMbtu/h

. For new boilers with a heat input capacity less than 10 MMBtu/h, GACT is a management practice of a tune

- up because, as previously discussed, there are technical and economic limitation s of conducting PM testing on boilers with small diameters stacks

. Tune

- ups Comment: Several commenters expressed concern regarding proposed work practice standards for existing area source boilers, including the requirement of a tune

- up for control of
POM and mercury

. Commenters stated that tune

- ups aimed at reducing CO may increase NOx emissions, reduce combustion efficiency, and/or increase fuel use. Commenters noted that many typical tune

- up requirements, including States '

re quirements, are aimed at minimization of NOx and not CO
. These commenters stated that the proposed tune

- up requirements could v iolate the state tune

- up requirements due to increases of
NOx
. Multiple commenters requested that EPA specify that tune

ups con sider optimizing efficie ncy and limiting increases of
NOx , and not only require minimizing CO

.**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **112** of **255** Other commenters requested that EPA allow the use of portable instruments to measure CO for the tune

- up requirements

. Several commenters requested that EPA cl arify that, for the
tune

- up procedures , gases do not have to measured using EPA Reference Methods

. These commenters indicated that requiring EPA Methods would increase the cost burden for small facilities. Response : EPA disagrees with commenters and is r equiring
tune

- ups as a work practice standard for coal

- fired area source boilers with a heat input capacity less than 10 MMBtu/h and as a management practice standard for all biomass

- fired and oil

- fired area source boilers

. EPA acknowledges that that a tu ne - up designed to specifically decrease CO emissions from an area source boiler would potentially increase emissions of NO x . However, it was not EPA's intent to require that area source boilers be specifically tune d for the reduction of CO emissions , but rather to require good combustion practices ( GCP ) by ensuring that area source boilers are tuned to manufacturer's specifications. As discussed in the preamble to the June 2010 proposed rule, boilers may be, at best, 85 percent efficient, and untuned boil ers may have combustion efficiencies of 60 percent or lower. Furthermore, as the combustion efficiency decreases, fuel usage increases to maintain energy output**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **113** of **255** resulting in increased emissions. A tune

- up performed to the manufacturer's specifications wo uld ensure the highest energy efficiency and reduce fuel usage, which will ultimately reduce HAP emissions. As commenters noted, the tune

- up requirements specified by area source boiler manufacturers are generally aimed at reducing NO X and would not incre ase emissions of NO X . Therefore, the tune

- up provisions incorporated in this final rule for area source boilers require that the owner or operator measure the concentration in the effluent stream of CO in ppm , by volume, dry basis ( ppmvd ), before and afte r adjustments are made to the boiler. EPA does not specify the instrument that must be used for measuring these concentrations, and allows owners and operators to choose the method of measurement. Therefore, EPA agrees with commenters that portable instr uments are permissible for this purpose.
F. Subcategories
Comment: Several commenters raised concerns regarding the subcategories defined by EPA in the development of the proposed rule. Multiple commenters argued that the proposed subcategories are u nlawful and arbitrary because they are not based on different classes, types, or sizes. At least one commenter specifically stated that the proposed**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **114** of **255** subcategorization defied the explicit recommendation of the Small Entity Representatives ( SERs ) to the Sma ll Business Advocacy Review ( SBAR ) Panel, which recommended that “EPA should subcategorize based on fuel type, boiler type, duty cycle, and location.” Many of these commenters suggested subcategories based on limited use, type of biomass (wood, bark, agri cultural residue, moisture level) and/or coal (bituminous, anthracite), boiler design (stoker, fluidized bed, or suspension), heat input capacity smaller than 1 MMBtu/h, and combustion of secondary
mate rials. Other commenters re commended that the same sub categories applied to major sources should be used for area

sources. Response: EPA disagrees with commenters. The CAA allows EPA to divide source categories into subcategories when differences between given types of units lead to corresponding differenc es in the nature of emissions or the technical feasibility of applying emission control techniques. The design, operating, and emissions information that EPA reviewed during the area source rulemaking indicates the need to subcategorize based on boiler de sign which is based on the fuel type. EPA continues to believe that this subcategorization is appropriate. As noted in the preamble to the June 2010 proposed**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **115** of **255** rule, boiler systems are designed for specific fuel types (e.g., coal, biomass, or oil) and will encounter problems if a fuel with characteristics other than those originally specified is fired. EPA has noted that emissions from boilers burning coal, biomass, and oil will also differ, and that HAP formation, including emissions of metals and mercury , is dependent upon the composition of the fuel. Organic HAP, on the other hand, are formed from incomplete combustion, which are a function of time, turbulence, and temperature, and are influenced by the design of the boiler and dependent in part on the type of fuel being burned. B ecause these different types of boilers have different emission characteristics which may influence the feasibility and effectiveness of emission control, we believe that subcategorizing them by fuel type is appropriate. Addi tionally, EPA notes that we lack sufficient emissions data for area source boilers to develop limits for additional subcategori es . We have elected to establish different subcategories for the major and area source rulemakings, as major source boilers have a different scale of operation and often different combustor desig n s . There is also more detailed emissions data available for the major source category, which favors the development of more specific subcategories. Because**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **116** of **255** we lack the same level of deta il for the area source category, EPA has determined that it would be inappropriate to establish the same subcategories for major and area source boilers. However, a s discussed in the comments below, we have established a small units sub category for each type of fuel (area source boilers with a heat input capacity of less than 10 MMBtu/h), and see no further need for smaller subcategories. We have also adjusted the definition for each fuel subcategory to account for the combustion of secondary materials. The definitions have been clarified to specify that the fuel subcategories are based on the fuel that the boiler is designed to combust , rather than the actual fuel that the boiler is combusting. Finally , as discussed earlier in this section, we have

r evised the MACT and GACT limits for the coal, oil, and biomass subcategories in this final rule

. Existing o il and biomass

fired boilers are no longer required to meet emission limits, and are only required to meet management practice standards under this final rule . Furthermore, coal

- fired boilers with a heat input capacity of less than 10 MMBtu/h are only required to meet work practice standards. While more stringent limits under this final rule may have required subcategories based on the**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **117** of **255** size of the u nit, EPA has determined that the subcategories chosen are reasonable based on the applicable req uirements of this final rule

. Combustion of Secondary Fuels
Comment: Multiple commenters sought clarity for the combustion of secondary materials and/or altern ative fuels within the proposed subcategories for area source boilers. Several of these commenters requested clarification of the defined fuels for the biomass, coal, and oil

- fired subcategories, as well as additional clarification regarding
gas - fired boi lers. Some commenters stated that EPA's determination that the boilers subject to this rule do not combust any non

- hazardous secondary materials is erroneous, and that to not consider standards for units burning secondary materials would be unlawful.
Ma ny commenters recommended that EPA classify boilers based on predominant use of a particular fuel; several commenters recommended redefining the subcategories to allow minimal burning of other fuels or for further clarification. For instance, some comment ers expressed concern regarding “combination boilers” (boilers that co

- fire coal in an amount greater than 10 percent heat input basis with at least 10**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **118** of **255** percent biomass), which do not cleanly fit into either the coal

fired boiler subcategory or the biomass

- fired boiler subcategory. Other commenters argued that the definition of
gas - fired boilers should allow for units burning less than 10 percent liquid fuels. Many of the commenters suggested alternative definitions for the proposed subcategories or provid ed alternative thresholds. Alternatively, there were some commenters who expressed concern regarding the use of alternative fuels. Commenters specifically stated that allowing 10 percent alternative fuel use, or use of multiple alternatives from year to year, would create significant enforcement issues for states without detailed requirements for tracking, recordkeeping, and reporting. Response: EPA has considered these comments and revised the subcategories based on a revised MACT floor approach. As discussed in Section I V.A of this preamble, we have redefined the coal, biomass and oil subcategories for area source boilers to clarify the fuel inputs that define each subcategory. While the subcategories under the proposed rule accounted for secondary materials such as biomass, liquid or gaseous fuels combusted in combination with traditional fuels , we wished to**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **119** of **255** clarify each subcategory in order to account for the combustion of an array of secondary fuels. Area source boilers combusting coal, biomass o r oil may also combust secondary materials as part of their fuel mix . It was not our intent to exclude boilers combusting these non - hazardous secondary materials that do not meet the definition of "solid waste" from the coal, biomass or oil

- fired subcateg ories. Therefore, we have revised the definition for each subcategory to account for the combustion of these non

- hazardous secondary materials

. For instance, the proposed rule limited the coal subcategory to boilers combusting coal or coal in combin ation with biomass, liquid, or gaseous fuels. We have redefined the coal subcategory to include boilers that burn any solid fossil fuel and no more than 15 percent biomass on an annual heat input basis. " Solid fossil fuels " has been defined to include , b ut not limited to, coal, petroleum coke, coal refuse, and tire derived fuel ( TDF ). Similarly, we have revised the biomass subcategory to account for boilers that may burn biomass and secondary materials . The biomass subcategory includes boilers combustin g at least 15 percent of biomass. This definition differentiates these primarily biomass

- fired boilers from the coal subcategory. Additionally, t he o il subcategory has been**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **120** of **255** revise d to include boilers that burn any liquid fuel but are not included in eith er the coal or biomass subcategories

. Based on new data submitted during the public comment period, EPA has determined that area source boilers may combust secondary materials. Data submitted indicates that as much as 15 percent of secondary materials , or alternative traditional fuel, may be mixed without causing problems with boiler operations. We wished to differentiate boilers combusting greater than 15 percent of biomass from the remaining subcategories, as these fuels will have higher rates of orga nic HAP. The revised definitions for the coal, biomass and oil subcategories clarify this by establishing the fuel type and the input ratio of each fuel type combusted. Therefore, the revised definitions more accurately reflect EPA's intent to include an d account for boilers combusting secondary materials in the coal, biomass, and oil subcategories and the effect of biomass on the combustion process

. Comment: A number of commenters requested that EPA provide exemptions for specific unit types, includ ing limited use boilers, recovery boilers, hot water heaters, boilers firing ultra low sulfur #2 fuel oil, and boilers with a heat input capacity of less than 1 MMBtu/h. Other commenters stated that**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **121** of **255** EPA is not justified in providing an exemption for gas

- f ired boilers. Response: As noted in Section VII of the proposed June 2010 rule, i n the Federal Register notice “ Source Category Listing for Section 112(d)(2) Rulemaking Pursuant to Section 112(c)(6) Requirements, ” ( 63 FR 17838, 17849 ) , Table 2 (1998),
E PA identified “Industrial Coal Combustion,” “Industrial Oil Combustion,” Industrial Wood/Wood Residue Combustion,” “Commercial Coal Combustion,” “Commercial Oil Combustion,” and “Commercial Wood/Wood Residue Combustion” as source categor ies

“ subject to reg ulation ” for purposes of CAA s ection 112(c)(6 )
. Notably, gas

- fired units are not included in the source category listing for area source boilers. Without such a listing , EPA cannot address gas - fired boilers in this regulation. We have also included in t his final rule an exemption for hot water heaters because these units are, as defined in this final rule , considered residential boilers. In addition, recovery boilers would be exempt because they are regulated under another section 112 MACT standard.
C onversely, EPA is required to set standards for other unit types, including limited use boilers and boilers firing ultra low sulfur fuel oil. These boilers are included in the source**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **122** of **255** category listing for CAA section 112(d)(2) and emit the pollutants ident ified in CAA section 112(c)(3). As discussed above, EPA has set appropriate MACT and GACT limits to boilers based on fuel type and size, including area source boilers with a heat input capacity of less than 10 MMBtu/h. EPA also notes that w aste heat boil ers have been excluded from th e definition of boiler

. G. Startup, Shutdown, and Malfunction
Comment: Several commenters stated that a separate standard must be developed for periods of startup and shutdown. Commenters stated that requiring emission lim its during SSM directly conflicts with the requirement that MACT be achievable and is technically feasible ; therefore EPA could not require emission limits during periods of SSM. Some commenters requested a separate standard for CO for startup ; a t least o ne commenter specifically stat ed that many area source boilers must operate under conditions d riven by safety considerations , operational concerns , and warranty requirements that would likely generate unavoidable increases in CO emissions during startup an d shutdown . The commenter therefore concluded that requiring a CO emission limit during startup and shutdown would not only be technically unachievable, but w ould promote unsafe**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **123** of **255** and improper operation

. Several c ommenters suggest ed that work practice stan dard s are mo re appropriate than emission limits, citing a lack of relevant data for periods of SSM

. Other commenters specifically objected to EPA's decision to base the SSM requirements on data from the proposed major source NESHAP for industrial, commerc ial, and institutional boilers and stated that the data from the proposed major source rule cannot be applied to area sources. Response: EPA has considered these comments and revised this final rule to incorporate work practice standards for periods of startup and shutdown . As part of the development of the proposed rule, we reviewed the cost information for CO CEMS provided by commenters on the NESHAP for major source boiler s and determined that requiring CO CEMS for units with heat input capacities gr eater or equal to 100 MMBtu/hr was reasonable. However, EPA has revised this final rule to only require emission limits for mercury and CO for coal

- fired boiler s. Furthermore, we are only requiring sources to perform work practice standards, including fo llowing the manufacturer's recommended procedures, to demonstrate compliance with the CO emission limits for area source coal

- fired boilers during periods of startup and shutdown. B ased on the available data set**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **124** of **255** for facilities in the affected area source c ategory , EPA determined that there are currently no existing coal

- fired boilers with a heat input capacity greater than 100 MMBtu/h located at area sources. Coal

- fired b oilers with a heat input capacity of greater than 50 MMBtu/h are generally major sourc es of HAP . Therefore, requiring CEMS for boilers of this size is unnecessary for the defined source category. In lieu of CEMS, w e also considered whether requirements for performance testing would be feasible for area source boilers during periods of st artup and shutdown. Upon review of these requirements, EPA determined that it is not f easible to require stack testing

- in particular , to complete the multiple required test runs

- during periods of startup and shutdown due to physical limitations and th e short duration of startup and shutdown periods

. Therefore, a separate standard must be developed for these periods. In regards to malfunctions, EPA had previously determined in the development of the proposed rule that malfunctions should not be viewe d 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

. As discussed in Section III.E**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **125** of **255** of this preamble, EPA has added to this final rule an affirmative defense for civil penalties for exceedances of numerical emission limits that are caused by malfunctions. Therefore, a s allowed under CAA section 112(h), we are requiring work practice standards for all coal

- fired area source boilers during periods of startup and shutdown. The work practice standards include following the boiler manufacturer's specifications for periods of startup and shutdown.
H. Compliance Requirements Rationale for Demonstrating Complia nce Comment: Several commenters expressed concern that, given the large numbers of boilers that would be affected by the proposed rule and the limited capacity of existing vendors, contractors, and engineers, a 3

- year time period would not be sufficient to allow completion of all of the required modifications

. Response: EPA has re

- evaluated the compliance dates for this final rule following the revised MACT and GACT standards. We have revised the initial compliance dates for existing affected sources a ccording to the a pplicable provisions for each affected source (e.g., work practice or management practice standards , emission limits, and/or an energy assessment), as**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **126** of **255** discussed in Section VI .E of this preamble. EPA has determined that e xisting sources su bject to a work practice standard of a
tune

- up must comply with this final rule no later than [ INSERT
THE DATE 1 YEAR AFTER THE DATE OF PUBLICATION OF IN THE FEDERAL
REGISTER ]. We have determined that one year is adequate time for affected sources to meet the work practice or management practice standard, which includes a tune

- up based on the manufacturer's recommendations. Existing sources subject to an emission limit or an energy assessment requirement are required
to comply with this final rule no late r than [ INSERT THE DATE 3
YEARS AFTER THE DATE OF PUBLICATION IN THE FEDERAL REGISTER ].
Comment: Commenters objected to proposed requirements to

use CEMS and in some circumstances COMS . Commenters stated that
t hese requirements are extremely burdensome on area sources considering the testing requirements and costs , and that t he requirement s for CO CEM S for units less than 100 MMBtu/h are too

onerous. Commenters noted that m any units at this size in the industrial and institutional sector do not operate frequently; therefore the cost of installing CO CEMS wa s not justified for units with such limited operation. Other commenters argued that

r equiring boilers to test for CO pos e s a significant regulatory burden

. Several commenters stated that the proposed testing**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **127** of **255** frequency was burdensome

. Response: EPA has considered these comments, and w e have

re vised the proposed continuous compliance requirements to not require a CO CEMS for area source boilers

. Per the revised MACT and GACT determinations, this final rule only requires emission limits for mercury and CO for coal

- fired units. Therefore, f or new and existing coal units with a heat input capacity greater than 10 MMBtu/h , we are requiring annual stack testing to demonstrate compliance with the CO emissio n limits. In the development of the proposed rule, we reviewed the cost information for CO CEMS provided by commenters on the NESHAP for major source boilers and determined that requiring CO CEMS for units with heat input capacities greater or equal to 10 0 MMBtu/h was reasonable. However, based on a review of the available dataset for facilities in the affected area source category, we have determined that there are currently no existing coal

- fired boilers with a heat input capacity greater than 100 MMBtu /h located at area sources. Therefore, requiring CEMS for coal

fired boilers of this size is unnecessary for the defined source category. Additionally, b oilers in the biomass and oil subcategories with a heat input capacity greater than 10 MMBtu/h

are no t required to meet emission limits for CO in this final**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **128** of **255** rule ; these boilers are subject to the management practice standards in Table 2 of 40 CFR part 63, subpart JJJJJJ , and therefore, no CO testing is required for these units.

I . Cost/Economic I mpact s Comment: Multiple commenters stated that the economic impacts of the proposed rule were significantly underestimated. Many commenters stated that the CO limits would require costly controls, and specifically, that the cost of particulate control for b iomass boilers was severely underestimated. Other commenters stated that EPA made erroneous assumptions in performing the cost calculations. For instance, one commenter stated that EPA does not have enough data to support the assumption that fabric filte rs alone will be sufficient for area source coal

- fired boilers to meet the proposed mercury limit

. Response: In light of changes to this final rule , EPA believes that these concerns are no longer an issue. We have revised the costs estimates for this final rule to reflect EPA's determination of the final MACT standards for coal

- fired boilers and GACT standards for biomass and oil

- fired boilers. For instance, EPA is only requiring particulate emission limits for new boilers with a heat input capacity o f greater than 10 MMBtu/h; smaller boilers must only meet the management practice**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **129** of **255** standard of a tune

- up. These changes have significantly decreased the costs presented in the proposed June 2010 rule. Additionally, commenters provided additional cost info rmation during the public comment period; EPA has inc or p o r ated this information into the analysis for this final rule . Based on this re

- analysis, EPA has determined that fabric filter controls are generally available and cost effective for new area source boilers. As noted previously, new area source boilers with a heat input capacity of 30 MMBtu/h or greater are subject to the NSPS for boilers (either subpart Db or Dc of 40 CFR part 60), which regulate emissions of PM and require performance testing.
Fu rthermore, new coal

- fired area source boilers will likely require a PM control device to comply with the proposed mercury MACT standard and required performance testing. W e determined in the context of the major source rulemaking, and from further analysi s of new data submitted during the public comment period, that fabric filters are the most effective technology employed by industrial, commercial, and institutional boilers for controlling mercury and particulate emissions. Therefore, EPA has determined it is appropriate and cost

- effective to estimate the cost of compliance based on fabric filter s for new area source boilers.**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **130** of **255** Comment: Some commenters stated that this final rule would have substantial impacts on rural communities. Commenters noted tha t m any rural communities rely upon or significantly benefit from the use of biomass boilers for energy at manufacturing facilities, schools and hospitals. These commenters stated that
t he proposed rule will negatively impact both boiler owners and fuel su ppliers in these communities. Similarly, other commenters stated that this final rule would have a significant adverse impact on the use of biomass renewable energy throughout the economy. Response: In light of the changes made to the final regarding bi omass - fired area source boilers, we believe these concerns are no longer an issue. Existing biomass area source boilers are only subject to the management practice of a tune

- up and only existing biomass

- fired area source boilers with a heat input capacity of 10 MM Btu/h or greater are required to have an energy assessment performed. There are no testing or monitoring requirements in this final rule for existing biomass

- fired area source boilers. New biomass

- fired area source boilers with a heat input
capa city of 10 MM Btu/h or greater are only subject to a PM emission limits which requires an annual PM test be conducted.**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **131** of **255**
**V I**  **. Summary of the I**  **mpacts of this**  **F inal**  **R ule** 
A. What are the air impacts ? Table 3 of this preamble illustrates, for each subcategory, the estimated emissions reductions achieved by th is rule (i.e., the difference in emissions between an area source boiler controlled to the MACT/GACT level of control and boilers at the current baseline) for new and existing sources. Nationwide emissions of total HAP ( HCl , hydrogen fluoride, non

- mercury metals, mercury, and VOC (for organic HAP) will be reduced by about 667 tpy for existing units and 74 tpy for new units. Emissions of mercury will be reduced by about 88 pounds per year for existing units and by about 9 pounds per year for new units. Emissions of filterable PM will be reduced by about 2,300 tpy for existing units and 280 tpy for new units. Emissions of non

mercury metals (i.e., antimony, arsenic, beryllium, cadmium, chromium, cobalt, lead , manganese, nickel, and selenium) will be reduced by about 280 tpy for existing units and will be reduced by 4 0 tpy for new units . Additionally, EPA has estimated that conducting an annual tune

- up will likely reduce emissions of organic HAP as a result o f improved combustion and reduced fuel

use. POM reductions are represented by 7

- PAH, a group of polycyclic aromatic hydrocarbons. EPA estimates that the energy**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **132** of **255** efficient work and management practices may reduce emissions of
7

- PAH by 8 tpy for existing un its and that the CO emission limit may reduce emissions of 7

- PAH by 1 tpy for new units. A discussi on of the methodology used to estimate baseline emissions and emissions reductions is presented in “Estimation of Impacts for Industrial, Commercial, and In stitutional Boilers Area Source NESHAP” in the docket. **Table 3**  **. Summary of HAP Emissions Reductions for Existing and**  **New Sources (tpy)**

**Source Subcategory**  **PM Non**  **Mercury Metals**  **a Mercury**  **POM b**  Existing Units Coal 1,092 4 0.003 0.2 Biomass 815 11 0.003 5 Oil 349 269 0. 04 3 New Units Coal 7 0.03 0.0 001 0.02 Biomass 121 2 0. 0002 0.5 Oil 149 36 0. 004 0.5

a Includes antimony, arsenic, beryllium, cadmium, chromium, cobalt, lead, manganese, nic kel, and selenium

. b POM is represented by total emissions of polycyclic aromatic hydrocarbons (7

- PAH). It is assumed that compliance with work practice standard and management practice will reduce fuel usage by 1 percent, which may reduce emissions of 7

- PAH by an equivalent amount.
B. What are the cost impacts ?**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **133** of **255** To estimate the national cost impacts of th is rule for existing sources, EPA developed several model boilers and determined the cost of control for these model boilers. EPA assigned a model boi ler to each existing unit based on the fuel, size, and current controls. The analysis considered all air pollution control equipment currently in operation at existing boilers. Model costs were then assigned to all existing units that could not otherwise meet the proposed standards. The resulting total national cost impact of th is rule for existing units is $ 487 m illion dollars in total annualized costs. The total annualized costs (new and existing) for installing controls, conducting bie nn i al tune

- up s and an energy assessment, and implementing testing and monitoring requirements is $ 535 million

. Table 4 of this preamble shows the total annualized cost impacts for each subcategory. **Table 4**  **. Summary of Annual Costs for New and**  **Existing Sources**

**Source S**  **ubcategory Estimated/**  **Projected No. of**

**Affected Units Total**  **Annualized Cost**  **( $**  **10 6**  **/yr) a**  Existing Units Coal 3,710 37 Biomass 10,958 24 Oil 168,003 374**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **134** of **255** Facility Energy A ssessme nt All 52

New Units b Coal 155 0.4 Biomass 200 2.6 Oil 6,424 45 a TAC does not include fuel savings from improving combustion efficiency. b Impacts for new units assume the number of units online in the first 3 years of this rule (2010 to 2013). Using D epartment of Energy projections on fuel expenditures, as well as the history of installation dates of area source boilers in the dataset, the number of additional boilers that could be potentially constructed was estimated. The resulting total national cost impact of th is proposed rule

on new s ources by the third year, 2013, is $ 48 m illion dollars in total annualized costs. When accounting for a 1 percent fuel savings resulting from improvements to combustion efficiency, the total national cost impact on new sources is

- ($3.6

m illion )
. A discu ssion of the methodology used to estimate cost impacts is presented in the memorandum , “Estimation of Impacts for Industrial, Commercial, and Institutional Boilers Area Source NESHAP” in the Docket.
C. What are the economic impacts ?**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **135** of **255** The economic impact a nalysis ( EIA ) that is included in the RIA shows that the expected prices for industrial sectors could be 0 .01 percent higher and domestic production may fall by less than 0 .01 percent. Because of higher domestic prices, imports may rise by less than 0.01 percent. Energy prices will not be affected. Social costs are estimated to be also $0.49 billion in 2008 dollars. This is estimated to made up of a $0.24 billion loss in domestic consumer surplus, a $0.24 billion loss in domestic producer surplus, a $0.004 billion increase in rest of the world surplus, and a $0.0.003 billion net loss associated with new source costs and fuel savings not modeled in a way that can be used to attribute it to consumers and producers. EPA performed a screening analy sis for impacts on small entities by comparing compliance costs to sales/revenues (e.g., sales and revenue tests). EPA’s analysis found the tests were typically higher for small entities included in the screening analysis. EPA has prepared an Initial Reg ulatory Flexibility Analysis ( IRFA ) that discusses alternative regulatory or policy options that minimize this final rule ’s small entity impacts. It includes key information about key results from the Small Business Advocacy Review ( SBAR ) panel.**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **136** of **255** For this RIA employment impacts are modeled based on empirical results from a peer

- reviewed study Morgenstern, Pizer and Shih (2002) that explores the relationship between employment and environmental regulation. Morgenstern et al. identify three separate compone nts of the employment change in response to a regulation:

 higher production costs raise market prices, higher prices reduce consumption (and production) reducing demand for labor within the regulated industry (“demand effect”);

 As costs go up, plants add more capital and labor. For example, pollution abatement activities require additional labor services to produce the same level of output (“cost effect”);

 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”). Morgenstern et al. empirically estimate a model for four highly polluting, regulated industries to examine the effect of higher abatement costs from regulation on employment. They conclude that in creased abatement expenditures generally do not cause a significant change in employment. More specifically, their results show that, on average across the four industries, each additional $1 million spending on pollution abatement results in a (statistic ally insignificant) net increase of 1.5 jobs. Furthermore they find that for two of the industries (pulp and paper, and steel) additional abatement spending leads to a**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **137** of **255** statistically positive, yet quite small, net increase in jobs due to substituting labor for other inputs and relatively inelastic estimated demand for their output. 4 Finally there are two effects that Morgenstern et al. do not consider. The first is the effect regulation has on employment in industries that make substitute products. Employme nt goes up in the production of these substitute products as consumers respond to changes in prices. For example, more expensive virgin paper will cause a shift to more recycled paper. The recycled paper industry will employ more workers as sales increas e. Similarly, employment in industries that are complements may decrease. The second is changes in employment at firms that make pollution control devices or provide consulting services employed in design and installation of control devices. For example , a recent study by Industrial Economics shows that a $19 million order for a new scrubber will immediately fund 77 to 91 new jobs for a year constructing and installing the new equipment. It will also create 16 permanent jobs to operate the new equipment . [Memorandum to Ellen

4 These results are similar to Berman and Bui (2001) who find that while sharply incr eased air quality regulation in Los Angeles to reduce NOx emissions resulted in large abatement costs they did not result in substantially reduced employment.**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **138** of **255** Kurlansky (EPA) from: Jason Price, Nadav Tanners, and Jim Neumann (IEc) and Roy Oommen (ERG), “Employment Impacts Associated with the Manufacture, Installation, and Operation of Scrubbers,” January 15, 2010] Parameters estimated in the Morgenstern et al. paper were used to estimate three types of employment effects (“demand,” “cost,” and “factor shift”). We believe the transfer of parameter estimates from the Morgenstern et al. study to this rule seems appropriate, as it is a well

- respected, peer

- reviewed study based on standard micro

- economic theory. ”Furthermore , the results of the Morgenstern et al. work also allow us to estimate the “cost effect” and the “factor

- shift effect,” as well as the “demand effect” to get a more comple te sense of how regulation affects employment. We calculated a “demand effect” estimate that used the Morgenstern et al. paper. EPA selected this paper because the parameter estimates (expressed in jobs per million ($1987) of environmental compliance expe nditures) provide a transparent and tractable way to transfer estimates for an employment effects analysis. Similar estimates were not available from other studies. To do this, we multiplied the point estimate for the total dem and effect ( −3.56 jobs per million ($1987) of**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **139** of **255** environmental compliance expenditure) by the total environmental compliance expenditures used in the partial equilibrium model. For example, the jobs effect estimate for the major source rule is estimated to b e about 6,000 jobs ( −3.56× $2,700 million × 0.60). 5 Demand effect results are provided in Table 5

. 6

**Table 5. Job Losses/Gains Associated**  **with the Rules**
Method 1,000 Jobs
Literature - based estimate (net effect [A + B +C b elow]) 1 ( - 1 to 2)
A. Literature

- based estimate: Demand effect - 1 (

- 3 to 0)
B. Literature

- based estimate: Cost effect 1 (0 to 1) C. Literature

- based estimate: Factor shift effect 1.0

5 Since Morgenstern’s analysis reports environmental expenditures in $1987, we make an inflation adjustment the engineering cost analysis using GDP implicit price deflator (64.76/108.48) = 0.60) 6 For comparison purposes, we also calculated “demand effect” employment changes by assuming that the number of jobs declines proportionally with the multi

- market model’s simulated output changes. These results were calculated for all sectors in the EPA model that show a change in output. For the selected option for Major sources this second way of estimating the “demand effect” resulted in an estimate of 400 0 jobs lost compared to the estimate using the Morgenstern parameters of 6000 jobs lost. Similarly, for the selected option for Area sources, this second way of estimating the “demand effect” resulted in the same estimate of 1000 jobs lost as the estimat e using the Morgenstern parameters. For the combination of the selected options for both Major and Area sources, this second way of estimating the “demand effect” resulted in an estimate of 5000 jobs lost compared to the estimate using the Morgenstern par ameters of 7000 jobs lost.**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **140** of **255** (

- 1 to 2) Note: Totals may not add due to independent rounding. 95 percent confidence intervals for literature

- based estimates are shown in parenthesis.
We also present the results of using the Morgenstern et al. paper to estimate employment “cost” and “factor

- shift” effects. Although using the Morgenstern et al. parameters to estimate these “cost” and “factor

- shift” employment changes is uncertain, it is helpful to compare the potential job gains from these effects to the job losses associa ted with the “demand” effect. Table 5 shows that using the Morgenstern et al. point estimates of parameters to estimate the “cost” and “factor shift” employment gains may be greater than the employment losses estimated for the “demand” employment losses. The 95 percent confidence intervals are shown for all of the estimates based on the Morgenstern et al. parameters. As shown, at the 95 percent confidence level, we cannot be certain if net employment changes are positive or negative. Although the Morgens tern et al. paper provides information about the potential job effects of environmental protection programs, there are several qualifications EPA considered as part of the analysis. First, EPA has used the weighted average parameter estimates for a narrow set of manufacturing industries (pulp and paper, plastics, petroleum, and steel). Absent other**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **141** of **255** data and estimates, this is a methodologically sound approach as these estimates come from a peer

- reviewed source. However, EPA acknowledges the current rules cover a broader set of industries not considered in the original empirical study. By transferring the estimates to other industrial sectors, we make the assumption that estimates are similar in size. In addition, EPA assumes also that Morgenstern et al. ’s estimates derived from the 1979

– 1991 time period are still applicable for policy taking place in 2014, over 20 years later. Third, Morgenstern et al. identifies the industry average as economically and statistically insignificant effect (i.e., the poin t estimates are small, measured imprecisely, and not distinguishable from

zero )
. EPA acknowledges this fact and thus has reported the 95 percent confidence intervals in Figure 4

- 4. Fourth, Morgenstern et al.’s methodology assumes that regulations affect plants in proportion to their total costs. In other words, each additional dollar of regulatory burden affects a plant by an amount equal to that plant's total costs relative to the aggregate industry costs. By transferring the estimates, EPA

assumes a s imilar distribution of regulatory costs by plant size and that the regulatory burden does not disproportionately fall on smaller plants. Fifth, there are two categories of job**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **142** of **255** effects which are beyond the scope of Morgenstern et al.’s study. One is emplo yment at firms that manufacture pollution control equipment or provide consulting services to design and/or installation pollution control equipment. Employment in these sectors would likely increase as firms purchase more pollution control equipment and services to meet the promulgated rule’s requirements. The second is the impact on employment in industries that make substitute products or complementary products. However, EPA does not currently have sufficient information to provide estimates of job ga ins from these sources for these particular rules

. D. What are the benefits ? We estimated the monetized benefits of this final regulatory action to be $210 million to $520 million (2008$, 3 percent discount rate) in the implementation year (2014). The monetized benefits at a 7 percent discount rate are $190 million to $470 million (2008$). Using alternate relationships between

PM 2.5 and premature mortality supplied by experts, higher and lower benefits estimates are plausible, but most of the expert

ba sed estimates fall between these two estimates. 7

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

– 2274. A summary of**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **143** of **255** the monetized benefits estimates at discount rates of 3 percent and 7 percent are provided in Table 6 of this preamble. A summary of the avoided health benefits are provided in Table 7 of this preamble. **Table 6**  **. Summary of the Monetized Benefits Estimates for the Final Boiler Area Source Rule (millions of 2008$)** 
Pollutant Emissions Reductions (tons) Total Monetized Benefits (at 3% discount rate) Total Monetized Benefits (at 7% discount rate) Direct PM 2.5 678 $79 to $190 $72 to $180 SO 2 3,197 $130 to $320 $120 to $290 Total $210 to $520 $190 to $470 1 All estimates are for the implementation year (2014), and are rounded to two significant figures so numbers may not sum across rows. All f ine particles are assumed to have equivalent health effects. Benefits from reducing HAP are not included. These estimates do not include energy disbenefits valued at less than $1 million. These benefits reflect existing boilers and 6,779 new boilers ant icipated to come online by 2014. **Table 7**  **. Summary of the Avoided Health Incidences for the Final Boiler MACT**  **Avoided Health Incidences**  **Avoided Premature Mortality** 24 to 61 **Avoided Morbidity** Chronic Bronchitis 17 Acute Myocardial Infarction 40 Hos pital Admissions, Respiratory 6 Hospital Admissions, Cardiovascular 13 Emergency Room Visits, Respiratory 21 Acute Bronchitis 38 Work Loss Days 3,200 Asthma Exacerbation 420 Minor Restricted Activity Days 19,000**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **144** of **255** Lower Respiratory Symptoms 460 Upper Respiratory Symptoms 350

1 All estimates are for the implementation year (2014), and are rounded to two significant figures and whole numbers. All fine particles are assumed to have equivalent health effects. Benefits from reducing HAP are not included . These benefits reflect existing boilers and 6,779 new boilers anticipated to come online by 2014. These benefits estimates represent the human health benefits associated with reducing exposure to PM 2.5 . The PM reductions are the result of emission limits on PM as well as emission limits on other pollutants, including HAP. To estimate the human health benefits, we used the environmental Benefits Mapping and Analysis Program (BenMAP) model to quantify the changes in PM 2.5 - related health impacts and m onetized benefits based on changes in air quality. This approach is consistent with the recently proposed Transport Rule RIA. 8 For this final rule, we have expanded and updated the analysis since the proposal in several important ways. Using the Compre hensive Air Quality Model with extensions (CAMx) model, we are able to provide boiler sector

- specific air quality impacts attributable to the emission reductions anticipated from this final rule. We believe that this modeling provides

8 U.S. Environmental Protection Agency, 2010. RIA fo r the Proposed Federal Transport Rule. Prepared by Office of Air and Radiation. June. Available on the Internet at http://www.epa.gov/ttn/ecas/regdata/RIAs/proposaltrria_final.pdf**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **145** of **255** estimates that are m ore appropriate for characterizing the health impacts and monetized benefits from boilers than the generic benefit

- per - ton estimates used for the proposal analysis. To generate the boiler sector

- specific benefit

- per - ton estimates, we used CAMx to convert emissions of direct PM 2.5 and

PM 2.5 precursors into changes in ambient PM 2.5 levels and BenMAP to estimate the changes in human health associated with that change in air quality. Finally, the monetized health benefits were divided by the emission reducti ons to create the boiler
sector

- specific benefit

- per - ton estimates. These models assume that all fine particles, regardless of their chemical composition, are equally potent in causing premature mortality because there is no clear scientific evidence that would support the development of differential effects estimates by particle type. Directly emitted PM 2.5 and SO 2 are the dominant PM 2.5 precursors affected by this rule. Even though we assume that all fine particles have equivalent health effects, the b enefit

per - ton estimates vary between precursors because each ton of precursor reduced has a different propensity to form PM 2.5 . For example, SO 2 has a lower benefit

- per - ton estimate than direct

PM 2.5 because it does not directly transform into PM 2.5 , and**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **146** of **255** because sulfate particles formed from SO 2 emissions can transport many miles, including over areas with low populations. Direct

PM 2.5 emissions convert directly into ambient PM 2.5 , thus, to the extent that emissions occur in population areas, exposures t o direct PM 2.5 will tend to be higher, and monetized health benefits will be higher than for SO 2 emissions. Furthermore, CAMx modeling allows us to model the reduced mercury deposition that would occur as a result of the estimated reductions of mercury em issions. Although we are unable to model mercury methylation and human consumption of mercury

contaminated fish, the mercury deposition maps provide an improved qualitative characterization of the mercury benefits associated with this final rulemaking. 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 on both empirical (epidemiological) studies and judgments elicited from scientific experts, to characterize the uncertainty in the relationship between PM 2.5 concentrations and premature mortality. For this rule, we cite two key empirical studies,**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **147** of **255** one based on th e American Cancer Society cohort study 9 and the extended Six Cities cohort study. 10

EPA strives to use the b est available science to support our benefits analyses. We recognize that interpretation of the science regarding air pollution and health is dynamic and evolving. After reviewing the scientific literature and recent scientific advice, we have determined that the no

- threshold model is the most appropriate model for assessing the mortality benefits associated with reducing PM 2.5 exposure. Consistent with this recent advice, we are replacing the previous threshold sensitivity analysis with a new LML assess ment . While an LML assessment provides some insight into the level of uncertainty in the estimated PM mortality benefits, EPA does not view the LML as a threshold and continues to quantify PM

- related mortality impacts using a full range of modeled air qua lity concentrations. In the RIA for this rule, which is available in the docket, we also include benefits estimates derived from expert judgments and other assumptions.

9 Pope et al, 2002. “Lung Cancer, Cardiopulmonary Mortality, and Long

- t erm Exposure to Fine Particulate Air Pollution.” Journal of the American Medical Association 287:1132

- 1141
. 10 Laden et al, 2006. “Reduction in Fine Particulate Air Pollution and Mortality.” American Journal of Respiratory and Critical Care Medicine. 17 3: 667

- 672
.**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **148** of **255** Most of the estimated PM

- related benefits in this rule would accrue to populations exposed to higher levels of PM 2.5 . Using the Pope, et al., (2002) study, 79 percent of the population is exposed at or above the LML of 7.5 μg/m 3 . U sing the Laden, et al., (2006) study, 34 percent of the population is exposed above the LML of 10 μg/m 3 . It is important to emphasize that we have high confidence in PM 2.5 - related effects down to the lowest LML of the major cohort studies. This fact is i mportant, because as we estimate PM

- related mortality among populations exposed to levels of PM 2.5 that are successively lower, our confidence in the results diminishes. However, our analysis shows that the great majority of the impacts occur at higher

ex posures. 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 benefit s from reducing other pollutants have not been monetized in this analysis, including reducing 1,100 tons of CO , 340 tons of HCl , 8 tons of HF, 90 pounds of mercury, and 320 tons of other metals each year. Although we do not have sufficient information or modeling available to provide monetized estimates**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **149** of **255** for this rulemaking, we include a qualitative assessment of the health effects of these air pollutants in the RIA for this rule, which is available in the docket. In addition, the monetized benefits estima tes provided in Table 6 do not reflect the disbenefits associated with increased electricity usage from operation of the control devices. We estimate that the increases in emissions of CO 2 would have disbenefits valued at less than $1 million at a 3 perce nt discount rate (average). CO 2 - related disbenefits were calculated using the social cost of carbon, which is discussed further in the RIA. However, these disbenefits do not change the rounded total monetized benefits. In the RIA, we also provide the

mo netized CO 2 disbenefits using discount rates of 5 percent (average), 2.5 percent (average), and 3 percent (95th percentile). This analysis does not include the type of detailed uncertainty assessment found in the 2006 PM 2.5 NAAQS RIA or 2008 Ozone NAAQS RIA. However, the benefits analyses in these RIAs provide an indication of the sensitivity of our results to various assumptions, including the use of alternative concentration

- response functions and the fraction of the population exposed to low PM 2.5 lev els.**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **150** of **255** For more information on the benefits analysis, please refer to the RIA for this final rule that is available in the docket.

E . What are the water and solid waste impacts ? EPA estimated that no additional water usage would result from the MACT flo or level of control or GACT requirement. The fabric filter, multiclone , or combustion control devices used to meet the standards of this rule do not require any water to operate, nor do they generate any wastewater. EPA estimated the additional solid was te that would result from th is rule to be 1,800 tpy for existing sources due to the dust and fly ash captured by mercury and PM control devices. The cost of handling the additional solid waste generated from existing sources is $ 75,700 per year. For new sources installed by 2013, the EPA estimated the additional solid waste that would result from th is rule to be 540 tpy for new sources due to the dust and fly ash captured by mercury and PM control devices. The cost of handling the additional solid waste generated from

new sources is $ 22,900 per year. These costs are also accounted for in the control costs estimates. A discussion of the methodology used to estimate impacts is presented in “Estimation of Impacts for Industrial, Commercial, and Institution al Boilers Area Source NESHAP” in the Docket.**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **151** of **255**
F . What are the energy impacts ? EPA expects an increase of approximately 25 m illion kWh in national annual energy usage from exi sting sources as a result of this rule. The increase results from the electrici ty required to operate control devices installed to meet th is rule, such as fabric filters. Additionally, for new sources installed by 2013, EPA expects an increase of approximately 8 million kWh in national annual energy usage in order to operate the cont rol devices. The Department of Energy has conducted energy assessments at selected manufacturing facilities and reports that facilities can reduce fuel/energy use by 10 to 15 percent by using best practices to increase their energy efficiency. Additional ly, the EPA expects work practice standards , such as boilers tune

ups , and combustion controls such as new replacement burners , will improve the efficiency of boilers. EPA estimates existing area source facilities can save 20 trillion B tu of fuel each
yea r. For new sources online by 2013, the EPA estimates 2. 3
tr illion BTU per year of fuel can be conserved. This fuel savings estimate includes only those fuel savings resulting from liquid and coal fuels and it is based on the assumption that the work prac tice standards will achieve 1 percent improvement in**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **152** of **255** efficiency.
**VI I**  **. Relationship of th**  **is Action to**  **CAA Section 112(c)(6)**
CAA s ection 112(c)(6) requires EPA to identify categories of sources of seven specified pollutants to assure that sources accounting for not less than 90 percent of the aggregate emissions of each such pollutant are subject to standards under
CAA s ection 112(d)(2) or 112(d)(4). EPA has identified “Industrial Coal Combustion,” “Industrial Oil Combustion,” Industrial Wood/Wood Residue C ombustion,” “Commercial Coal Combustion,” “Commercial Oil Combustion,” and “Commercial Wood/Wood Residue Combustion” as source categor ies that emit two of the seven CAA s ection 112(c)(6) pollutants: POM and mercury

. (The POM emitted is composed of 16 poly aromatic hydrocarbons ( PAH ).) In the Federal Register notice , Source Category Listing for Section 112(d)(2) Rulemaking Pursuant to Section 112(c)(6) Requirements, 63 FR 17838, 17849, Table 2 ( April 10, 1998), EPA identified “Industrial Coal Combustion,” “ Industrial Oil Combustion,” Industrial Wood/Wood Residue Combustion,” “Commercial Coal Combustion,” “Commercial Oil Combustion,” and “Commercial Wood/Wood Residue Combustion” as source categor ies

“ subject to regulation ” for purposes of CAA s ection 112(c)(6 ) with respect to the CAA s ection 112(c)(6) pollutants that these**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **153** of **255** units emit. Specifically, as by

- products of combustion, the formation of POM is effectively reduced by the combustion and post

combustion practices required to comply with the CAA s ection 1 1 2 standards. Any POM that do es form during combustion is further controlled by the various post

- combustion controls. The add

- on PM control systems (fabric filter) used to reduce mercury and/or
PM emissions further reduce emissions of these organic pollut ants, as is evidenced by performance data. Specifically, the emission tests obtained at currently operating major source boilers show that the MACT regulations for coal

- fired area source boilers will reduce Hg emissions by about 86 percent. It is, theref ore, reasonable to conclude that POM emissions from coal

- fired area source boilers will be substantially controlled. In lieu of establishing numerical emissions limits for pollutants such as POM, we regulate surrogate substances. While we have not identif ied specific numerical limits for POM, we believe CO serves as an effective surrogate for th i s HAP , because CO , like POM, is formed as a product of incomplete combustion. Consequently, we have concluded that the emissions limits for CO function as a surr ogate for control of POM, such that it**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **15 4**  of **255** is not necessary to establish numerical emissions limits for POM

w ith respect to coal

- fired area source boilers to satisfy CAA

s ection 112(c)(6). To further address POM and mercury emissions, th is rule also includes a n energy assessment provision that encourage s modifications to the facility to reduce energy demand that lead to these emissions.
**VIII .**  **Statutory And Executive Order Review**
A. Executive Order 12866 : Regulatory Planning and Review Under section 3(f)(1) of Executive Order 12866 (58 FR 51735, October 4, 1993), this action is an “economically significant regulatory action” because it is likely to have an annual effect on the economy of $100 million or more or adversely affect in a material way the economy, a sector of the economy, productivity, competition, jobs, the environment, public health or safety, or State, local, or tribal governments or communities. Accordingly, EPA submitted this action to OMB for review under EO 12866 and any changes in response to OMB recommendations have been documented in the docket for this action. In addition, EPA prepared an analysis of the potential costs and benefits associated with this action. This analysis**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **155** of **255** is contained in the Regulatory Impact Analysis (RIA) report. For more information on the costs and benefits for this rule, please refer to Section VI.C of this preamble.
B. Paperwork Reduction Act The information collection requirements in this rule have been submitted for approval to OMB under the Paperwork Redu ction
Act , 44 U.S.C. 3501 et seq

This NESHAP would require applicable one

- time notifications according to the NESHAP General Provisions. Facility owners or operators are required to include compliance certifications for . The information collection requirements are not enforceable until OMB approves them. The ICR document prepared by EPA has been assigned EPA ICR number 2253.01. The recordkeeping and reporting requirements in this rule a re based on the information collection requirements in EPA’s NESHAP General Provisions (40 CFR part 63, subpart A). The recordkeeping and reporting requirements in the General Provisions are mandatory pursuant to CAA section 114 (42 U.S.C. 7414). All inf ormation other than emissions data submitted to EPA pursuant to the information collection requirements for which a claim of confidentiality is made is safeguarded according to CAA section 114(c) and EPA’s implementing regulations at 40 CFR part 2, subpart B.**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **156** of **255** the work practices and management practices in their Notificati ons of Compliance Status. Recordkeeping is required to demonstrate compliance with emission limits, work practices, management practices, monitoring, and applicability provisions. New affected facilities are required to comply with the requirements for s tartup, shutdown, and malfunction reports and to submit a compliance report if a deviation occurred during the semiannual reporting period. The annual monitoring, reporting, and recordkeeping burden for this collection (averaged over the first 3 years aft er the effective date of the standards) is estimated to be $ 407 million. This includes 2.7 million labor hours per year at a cost of $254 million and total non

- labor capital costs of $153 million per year. This estimate includes initial and annual perfor mance tests, conducting and documenting an energy assessment, conducting and documenting a tune

- up, semiannual excess emission reports, maintenance inspections, developing a monitoring plan, notifications, and recordkeeping. Monitoring, testing, tune

- up a nd energy assessment costs were also included in the cost estimates presented in the control cost impacts estimates in Section VII.B of this preamble

. The total burden for the Federal government (averaged over the first 3 years**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **157** of **255** after the effective date of the standard) is estimated to be 286,000 hours per year at a total labor cost of $13 mill ion per
year. Burden is defined at 5 CFR 1320.3(b). An agency may not conduct or sponsor, and a person is not required to respond to, a collection of information un less the collection displays a currently valid OMB control number. The OMB control numbers for EPA’s regulations in 40 CFR part 63 are listed in 40 CFR part 9. When this ICR is approved by OMB, the Agency will publish a technical amendment to 40 CFR part 9 in the Federal Register to display the OMB control number for the approved information collection requirements contained in this final rule.
C. Regulatory Flexibility Act (RFA) The RFA generally requires an agency to prepare a regulatory flexibility analysis of any rule subject to notice and comment rulemaking requirements under the Administrative Procedure Act or any other statute unless the agency certifies that this final rule will not have a significant economic impact on a substantial number of s mall entities. Small entities include small businesses, small organizations, and small governmental jurisdictions. Pursuant to section 603 of the RFA, EPA prepared an initial**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **158** of **255** regulatory flexibility analysis (IRFA) for the proposed rule (see 75 FR 31896 ( June 4, 2010 )). Pursuant to section 609(b) of the RFA, EPA convened a Small Business Advocacy Review Panel to obtain advice and recommendations from representatives of small entities that would potentially be regulated by this final rule

. A detailed disc ussion of the Panel’s advice and recommendations is found in the Panel Report located in the docket. A summary of the Panel’s recommendations is presented in detail in the preamble to the proposed rule. See 75 FR 3191 8

- 31918
. This final rule will not h ave a significant economic impact

on a substantial number of small entities as a result of several decisions EPA made regarding the development of this final rule , which resulted in limiting the impact of this final rule on small entities. First, as menti oned earlier in this preamble,

EPA determined that coal

- fired area source boilers need only to be address under CAA section 112(c)(6). Therefore, the final standards for biomass

- fired boilers and oil

- fired boilers are based on GACT, as opposed to the prop osed MACT

- based emission limits. As also discussed earlier, EPA determined that for new small coal

- fired boilers (heat input of less than 10 MMBtu/h), it is appropriate to promulgate work practice standards, as allowed under CAA section 112(h), instead of the MACT

- based**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **159** of **255** emission limits. Many small coal

- fired boilers, biomass

- fired boilers, and oil

- fired boilers are located at small entities. Consequently, this final rule contains no emission limits , only work practice standards or management practice, fo r new and existing small coal

- fired boilers, existing biomass

- fired boilers, and existing oil

- fired boilers. After considering the economic impacts of today’s final rule on small entities, I certify that this action will not have a significant economic imp act on a substantial number of small entities. The small entities directly regulated by this final rule are small businesses, small governmental jurisdictions and small non

- profits.
D. Unfunded Mandates Reform Act of 1995 Title II of the Unfunded Mandat es Reform Act of 1995 (UMRA), Public Law 104

- 4, establishes requirements for Federal agencies to assess the effects of their regulatory actions on State, local, and tribal governments and the private sector. Under section 202 of the UMRA, we generally mus t prepare a written statement, including a cost

- benefit analysis, for proposed and final rules with “Federal mandates” that may result in expenditures to State, local, and tribal governments, in the aggregate, or to the private sector, of $100 million or m ore in**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **160** of **255** any 1 year. Before promulgating a rule for which a written statement is needed, section 205 of the UMRA generally requires us to identify and consider a reasonable number of regulatory alternatives and adopt the least costly, most cost

- effective or least burdensome alternative that achieves the objectives of this final rule . The provisions of section 205 do not apply when they are inconsistent with applicable law. Moreover, section 205 allows us to adopt an alternative other than the least costly, most cost

- effective or least burdensome alternative if the Administrator publishes with this final rule an explanation why that alternative was not adopted. Before we establish any regulatory requirements that may significantly or uniquely affect small g overnments, including tribal governments, we must develop a small government agency plan under section 203 of the UMRA . The plan must provide for notifying potentially affected small governments, enabling officials of affected small governments to have me aningful and timely input in the development of regulatory proposals with significant Federal intergovernmental mandates, and informing, educating, and advising small governments on compliance with the regulatory requirements. We have determined that this rule contains a Federal**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **161** of **255** mandate that may result in expenditures of $100 million or more for State, local, and Tribal governments, in the aggregate, or the private sector in any 1 year. Accordingly, we have prepared a written statement entitled “Unfunded Mandates Reform Act Analysis for the Boiler Area Source NESHAP" under section 202 of the UMRA which is summarized below. 1. Statutory Authority As discussed in S ection I of this preamble, the statutory authority for this rulemaking is CAA sectio n 112
. Title III of the CAA was enacted to reduce nationwide air toxic emissions. Section 112(b) of the CAA lists the 188 chemicals, compounds, or groups of chemicals deemed by Congress to be HAP. These toxic air pollutants are to be regulated by NESHAP. Secti on 112(d) of the CAA requires us to establish NESHAP for both major and area sources of HAP that are listed for regulation under CAA section 112(c). CAA section 112(k)(3)(B) calls for EPA to identify a t least 30 HAP which, as the result of emissions from area sources, pose the greatest threat to public health in the largest number of urban areas. CAA section 112(c)(3) requires EPA to list sufficient categories or subcategories of area sources to ensure that area sources represent ing 90 percent of the emis sions of the 30 urban HAP are**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **162** of **255** subject to regulation. Under CAA section 112(d)(5), we may elect to promulgate standards or requirements for area sources based on GACT used by those sources to reduce emissions of HAP. Determining what constitutes GACT invo lves considering the control technologies and management practices that are generally available to the

area sources in the source categor y. We also consider the standards applicable to major sources in the analogous source category and, as appropriate, th e control technologies and management practices at area and major sources in similar categories , to determine if the standards, technologies , and /or practices are transferable and generally available to area

sources. I n determining GACT for a particular a rea source category, we consider the costs and economic impacts of available control technologies and management practices on that category. While GACT may be a basis for standards for most types of HAP emitted from area source, CAA s ection 112(c)(6) requ ires that source categories accounting for emissions of the HAP listed in CAA section 112(c)(6) be subject to standards under CAA section 112(d)(2) for the listed pollutants. Thus, CAA section 112(c)(6) requires that emissions of each listed HAP for**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **163** of **255** the l isted categories be subject to MACT regulation. The CAA section 112(c)(6) list of source categories includes industrial boilers and institutional/commercial boilers. Within these two source categories, coal combustion, oil combustion, and wood combustion have been on the CAA section 112(c)(6) list because of emissions of mercury and POM. We currently believe that regulation of coal

- fired boilers will ensure that we fulfill our obligation under CAA section 112(c)(6) with respect to mercury and POM reducti ons. Consequently, we deem it reasonable to regulate the coal

- fired boilers under MACT, rather than the biomass and oil

- fired boilers, to obtain additional mercury and
POM reductions towards achieving the CAA section 112(c)(6) obligation. We are regulat i ng biomass

- fired and oil

- fired boilers under GACT. This NESHAP w ill apply to all existing and new industrial boilers, institutional boilers, and commercial boilers located at area sources. In compliance with section 205(a) of the UMRA, we identified and considered a reasonable number of regulatory alternatives. Additional information on the costs and environmental impacts of these regulatory alternatives is presented in the docket. The emission limits for existing area source boilers are**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **164** of **255** only applicabl e to area source boilers that have a designed heat input capacity of 10 MMBtu/h or greater. The regulatory alternative upon which the standards are based represents the MACT floor for the listed CAA section 112(c)(6) pollutants (mercury and POM) for coal

- fired units and GACT for the other urban HAP which formed the basis for the listing of these two area source categories. The standards w ill require new coal

fired boilers to meet MACT

- based emission limits for mercury and CO (as a surrogate for POM) and G ACT

- based emission limits for PM (as a surrogate for urban metals). New biomass and oil

- fired boilers w ill be required to meet GACT for CO , which are tune

ups, and GACT

- based emission limits for PM. Existing large coal

- fired boilers w ill be required to m eet MACT

- based emission limits for mercury and CO for coal

- fired units , and existing large biomass and oil

- fired boilers w ill be subject to GACT, which is a tune

- up . As allowed under CAA section 112(h), a work practice standard requiring the implementatio n of a tune

- up program is being established for existing and new area source boilers with a designed heat input capacity of less than 10

MM Btu /h . An additional “beyond

- the

- floor” standard is being established for existing area source facilities having an affected boiler with a heat input capacity of 10 MM Btu / h or**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **165** of **255** greater that requires the performance of an energy assessment on the boiler and the facility to identify cost

- effective energy conservation measures. 2. Social Costs and Benefits The regulato ry impact ana lysis prepared for this final rule including the Agency’s assessment of costs and benefits, is detailed in the “Regulatory Impact Analysis : National Emission Standards for Hazardous Air Pollutants for Industrial, Commercial, and Institutional Boilers and Process Heaters” in the docket. Based on estimated compliance costs associated with this final rule and the predicted change in prices and production in the affected industries, the estimated social costs of this final rule are $ [ 0.49 ] billio n (2008 dollars). It is estimated that 3 years after implementation of this final rule , HAP w ill be reduced by hundreds of tons, including reductions in metallic HAP including mercury, hydrochloric acid, hydrogen fluoride, and several other organic HA P from area source boilers. Studies have determined a relationship between exposure to these HAP and the onset of cancer ; however, the Agency is unable to provide a monetized estimate of the HAP benefits at this time. In addition, there are reductions in
PM 2.5 and in SO 2 that w ill occur, including 678 tons of PM 2.5 and**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **166** of **255** 3,197 tons of SO 2 . These reductions occur within 3 years after the implementation of the regulation and are expected to continue throughout the life of the affected sources. The major hea lth effect associated with reducing PM 2.5 and PM 2.5 precursors (such as SO 2 ) is a reduction in premature mortality. Other
health effects associated with PM 2.5 emission reductions include avoiding cases of chronic bronchitis, heart attacks, asthma attacks, and work

- lost days (i.e., days when employees are unable to work). While we are unable to monetize the benefits associated with the HAP emissions reductions, we are able to monetize the benefits associated with the PM 2.5 and SO 2 emissions reductions. Fo r SO 2.5 and PM 2.5 , we estimated the
benefits associated with health effects of PM but were unable to quantify all categories of benefits (particularly those associated with ecosystem and visibility effects). Our estimates of the monetized benefits in 2013 associated with the implementation of this final rule range from $ 0.21 billion (2008 dollars) to $ 0.52 billion (2008 dollars) when using a 3 percent discount rate (or from $ 0.19 billion (2008 dollars) to $ 0.47 billion (2008 dollars) when using a 7 percent discount rate. The general approach used to value benefits is discussed in more detail in Section VII.D of this preamble. For more detailed**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **167** of **255** information on the benefits estimated for the rulemaking, refer to the RIA in the docket. 3. Future and Disprop ortionate Costs The Unfunded Mandates Reform Act requires that we estimate, where accurate estimation is reasonably feasible, future complianc e costs imposed by this final rule and any disproportionate b udgetary effects. Our estimates of the future compliance costs of this final rule are discussed in Section
VII.C of this preamble. We do not believe that there will be any disproportionate bu dgetary effects of this final rule on any particular areas of
t he country, State or local governments, types of communities (e.g., urban, rural), or particular industry segments. See the results of the “Economic Impact Analysis of the Proposed Industrial Boilers and Process Heaters NESHAP,” the results of which are d iscussed in Section VII.C of this preamble. 4. Effects on the National Economy The Unfunded Mandates Reform Act requires that we estimate the effect of the proposed rule on the national economy. To the extent feasible, we must estimate the effect on productivity, economic growth, full employment, creation of productive jobs, and international competitiveness of the U.S. goods and**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **168** of **255** services, if we determine that accurate estimates are reasonably feasible and that such effect is relevant a nd material. The nationwide economic impact of this final rule is presented in the E conomic Impact Analysis chapter (Section 4) of the RIA in the docket. This analysis provides estimates of the effect of this final rule on some of the categories mentione d above. The results of the economic impact analysis are summarized in Section VII.C of this preamble. The results show that there will be a small impact on prices and output (less than 0.0 1 percent ) . In addition, there should be little impact
on energy markets (in this case, coal, natural gas, petroleum products, and electricity). Hence, the potential impacts on the categories mentioned above should be small.
5. Consultation with Government Officials The Unfunded Mandates Reform Act requires that we describe the extent of the Agency’s prior consultation with affected State, local, and tribal officials, summarize the officials’ comments or concerns, and summarize our response to those
comments o r concerns. In addition, section 203 of the UMRA requires that we develop a plan for informing and advising small governments that may be significantly or uniquely impacted by a proposal. Consistent with the intergovernmental consultation**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **169** of **255** provisions of s ection 204 of the UMRA, EPA has initiated consultations with governmental entities affected by this rule

. EPA invited the following 10 national organizations representing State and local elected officials to a meeting held on March 24, 2010 in Washington DC: (1) National Governors Association; (2) National Conference of State Legislatures, (3) Council of State Governments, (4) National League of Cities, (5) U.S. Conference of Mayors, (6) National Association of Counties, ( 7 ) International City/County Mana gement Association, ( 8 ) National Association of Towns and Townships, (9) County Executives of America, and (10) E nvironmental C ouncil of S tates . These 10 organizations of elected S tate and local officials have been identified by EPA as the “Big 10” organi zations appropriate to contact for purpose of consultation with elected officials. The purposes of the consultation were to provide general background on the proposal, answer questions, and solicit input from State/local governments. During the meeting, officials expressed uncertainty with regard to how boilers owned/operated by State and local entities would be impacted, as well as with regard to the potential burden associated with implementing this final rule on State and local entities. To that end, officials requested and EPA provided (1) m odel boiler costs , ( 2 ) i nventory**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **170** of **255** of area source boilers (coal, oil, biomass only) fo r the 13
S tates for which we have an inventory, and ( 3 ) i nformation on potential size of boilers used for various facility types a nd sizes. EPA has not received additional questions or requests from State or local officials. Consistent with section 205, EPA identified and considered a reasonable number of regulatory alternatives. Because an initial screening analysis for impact on small entities indicated a likely significant impact for substantial numbers , EPA convened a SBAR Panel to obtain advice and recommendation of representatives of the small entities that potentially would be subject to the requirements of this final rule

. As part of that process, EPA considered several options. Those options included establishing emission limits, establishing work practice standards, and establishing work practice standards and requiring an energy a ssessmen t. The regulatory alternative

s elected is a combination of the options considered and includes provisions regarding each of the SBAR Panel’s recommendations for area source boilers

. The recommendations regard the use of subcategori es , work practice standards, and compliance costs (see section IX .C of this preamble for more detail on the RFA ). EPA determined subcategori es based on boiler type to be**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **171** of **255** appropriate because different types of units have different emission characteristics which may affect the feasibility and effectiveness of em ission control. Thus, this final rule identifies three subcategories of area source boilers: (1) boilers designed for coal firing, (2) boilers designed for biomass firing, and (3) boilers designed for oil firing. The emission limits for existing and new area source boilers are only applicable to area source boilers that have a designed heat input capacity of 10 MMBtu/h or greater. A work practice standard (for mercury from coal

- fired boilers and for POM from all boilers) or management practice (for all o ther HAP, including mercury from biomass

- fired and oil

- fired boilers) requiring the implementation of a tune

- up program is being established for existing area source boilers with a designed heat input capacity of less than 10 MMBtu/h. The regulatory alter native upon which the standards are based represents the MACT floor for mercury and POM (CO is used as a surrogate for POM) for coal

- fired boilers, and GACT for the other urban HAP (PM is used as a surrogate for urban HAP metals and CO is used
as a surroga te for urban organic pollutants ) for new coal, biomass, and oil

- fired boilers. An additional “beyond

- the

floor” standard is being established for existing area source**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **172** of **255** facilities having an affected boiler with a heat input capacity of 10 MM Btu / h or greater that requires the performance of an energy assessment on the boiler and the facility to identify
cost

- effective energy conservation measures. The use of surrogate pollutants w ill result in reduced compliance costs because testing is only be required for t he surrogate pollutants (i.e., CO and PM) versus for the HAP (i.e., POM and metals). The work practice standard /management practice also w ill result in reduced compliance costs with respect to monitoring/testing for the smaller existing area source boiler s. EPA’s exemption of most area source facilities from title V permit requirements also w ill reduce burden on area source boiler facilities. This r ule is not subject to the requirements of section 203 of the UMRA because it contains no regulatory requirem ents that might significantly or uniquely affect small governments. While some small governments may have boilers that w ill be affected by this final rule , EPA’s analysis shows that other public facilities that are located at area source facilities owned by small entities w ill not have cost

- to

- revenue ratios e xceeding 10 percent . H ospitals’ and schools’ revenue tests fall below 1 percent . Because this final rule ’s requirements apply equally**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **173** of **255** to boilers owned and/or operated by governments and to boilers

o wned and/or operated by private entities , th ere w ill be no requirements that uniquely apply to such governments or impose any disproportionate impacts on them.
E. Executive Order 13132: Federalism Under Executive Order 13132, EPA may not issue an action that has federalism implications, that imposes substantial direct compliance costs, and that is not required by statute, unless the Federal government provides the funds necessary to pay the direct compliance costs incurred by State and local governments, or EPA consults with State and local officials early in the process of developing the proposed action. EPA has concluded that this action may have federalism implications, because it may impose substantial direct compliance costs on State or local gover nments, and the Federal government will not provide the funds necessary to pay those costs. Accordingly, EPA provides the following federalism summary impact statement as required by section 6(b) of Executive Order 13132. Based on the estimates in EPA’s R IA for today’s action, the regulatory option may have federalism implications because the action may impose approximately $ 276 million in annual direct**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **174** of **255** compliance costs on an estimated 57,000 State or local governments. Boiler inventories for the health s ervices, educational services, and government

- owned buildings sectors from 13 States were used to estimate the nationwide number of potentially impacted State or local governments. Because the inventories for these sectors include privately owned and Fede ral government owned facilities, the estimate may include many facilities that are not State or local government owned. Table 8 of this preamble presents estimates of the number of potentially impacted State and local governments and their potential annua l compliance costs for each of the three sectors. In addition to an estimate of the total number of potentially impacted facilities, estimates for facilities with small boilers and for facilities with large boilers are presented. Small boilers (boilers w ith heat input capacity of less than 10

MM Btu / h) w ill be subject to a work practice standard or management practice that requires a boiler tune

- up every 2 years. Large coal

- fired boilers ( boilers with heat input capacity of 10 MM Btu /h or greater ) w ill be subject to emission limits for mercury and CO . L arge biomass and oil

- fired boilers

w ill be subject to a biennial boiler tune

- up requirement for CO.**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **175** of **255** All facilities with large boilers w ill be required to conduct a

one - time energy assessment. **Table 8**  **. Stat e and local governments potentially impacted by**  **the standards for boilers at area source facilities**
Sector N umber of potentially impacted facilities Annual compliance costs to mee t standards Total Small Large Health Services 1 7,206 15,293 1,913 $ 84 m il lion Educational Services 3 4 ,052 33,303 749 $ 159 million Government

Owned Buildings 5,796 5,098 698 $ 33 million
Total 57,054 53,694 3,360 $ 276 m illion

EPA consulted with State and local officials in the process of developing the action to permit them to have meaningful and timely input into its development. EPA met with 10 national organizations representing State and local elected officials to provide general background on the propos ed rule , answer questions, and solicit input from State/local gover nments. The UMRA discussion in Section IX.D this preamble includes a description of the consultation. As required by section 8(a) of Executive Order 13132, EPA included a certification from its Federalism Official stating that EPA had met the Executive
O rder’s requirements in a meaningful and timely manner, when it sent the draft of this final action to OMB for review pursuant to Executive Order 12866. A copy of this certification has been**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **176** of **255** included in the public version of the official record for this fi nal action.

F . Executive Order 13175: Consultation and Coordination with Indian Tribal Governments Th is action does not have tribal implications, as specified in Executive Order 13175 (65 FR 67249, November 9, 2000)

. This final rule imposes requirement s on owners and operators of specified area sources and not tribal governments. We do not know of any industrial , commercial , or institutional boilers owned or operated by Indian tribal governments. However, if there are any, the effect of this final rul e on communities of tribal governments would not be unique or disproportionate to the effect on other communities. Thus, Executive Order 13175 d oes not apply to th is action

. G
. Executive Order 13045: Protection of Children from Environmental Health Risk s and Safety Risks Th is action is not subject to Executive Order 13045 because the Agency does not believe the environmental health risks or safety risks addressed by this action present a disproportionate risk to children. In addition, this action is

n ot subject to Executive Order 13045 because this final rule is based solely on technology performance.**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **177** of **255**
H. Executive Order 13211: Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution, or Use Th is action is not a “significa nt energy action” as defined in Executive Order 13211 (66 FR 28355 (May 22, 2001)) because it is not likely to have a significant adverse effect on the supply, distribution, or use of energy. We estimate no significant changes for the energy sector for pr ice, production, or imports. For more information on the estimated energy effects, please refer to Section VI of this preamble . The analysis is available in the public docket.

I . National Technology Transfer and Advancement Act Section 12(d) of the N ational Technology Transfer and Advancement Act (NTTAA) of 1995 (Public Law No. 104

- 113, Section 12(d), 15 U.S.C. 272 note) directs EPA to use voluntary consensus standards (VCS) in its regulatory activities, unless to do so would be inconsistent with appl icable law or otherwise impractical. The VCS are technical standards (e.g., materials specifications, test methods, sampling procedures, and business practices) that are developed or adopted by VCS bodies. The NTTAA directs EPA to provide Congress, throu gh OMB, explanations when the Agency does not use available and applicable VCS. This final rule inv olves technical standards. EPA cites**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **178** of **255** the following standards in this final rule : EPA Methods 1, 2, 2F, 2G, 3A, 3B, 4, 5, 5D, 10, 10A, 10B, 17, 19, 29 of 4 0 CFR part 60; 101A of 40 CFR part 61; and voluntary consensus standards: American Society of Mechanical Engineers (ASME) PTC 19 (manual methods only), American Society for Testing and Materials (ASTM) D6522

- 00, ASTM D6784

- 02, ASTM D2234/D2234M

– 10 , ASTM D 6323

- 98, ASTM D2013

- 04, ASTM D5198

- 92, ASTM D5865

- 04, ASTM E711

- 87, ASTM D3173

- 03, ASTM E871

- 82, and ASTM D6722

- 01. Consistent with the NTTAA, EPA conducted searches to identify voluntary consensus standards in addition to these EPA methods. No applicabl e voluntary consensus standards were identified as alternatives for EPA Methods 2F, 2G, 5D, and 19. The search and review results are in the docket for this rule. The search for emissions measurement procedures identified 16 other volu ntary consensus sta ndards. EPA determined that these 16 standards identified for measuring emissions of the HAP or surrogates subject to emission standards in this rule were impractical alternatives to EPA test methods for the purposes of this rule. Therefore, EPA d id not adopt these standards for this purpose. The reasons for th e determination s for the 16 methods can be found in the docket to this rule. Table 4 to subpart JJJJJJ of this rule lists the testing**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **179** of **255** method s included in the regulation. Under 40 CFR 6 3.7(f) and 63.8(f) of the General Provisions, a source may apply to EPA for permission to use alternative test methods or alternative monitoring requirements in place of any required testing methods, performance specifications, or procedures.
J. Executive Order 1289 8: Federal Actions to Address Environmental Justice in Minority Populations and Low

- Income Populations Executive Order 12898 (59 FR 7629, February 16, 1994) establishes Federal executive policy on environmental justice ( EJ ). Its main provision directs F ederal agencies, to the greatest extent practicable and permitted by law, to make EJ part of their mission by identifying and addressing, as appropriate, disproportionately high and adverse human health or environmental effects of their programs, policies, and activities on minority populations, low

- income, and Tribal populations in the United States. This action establishes national emission standards for industrial, commercial, and institutional boilers that are area sources. The industrial boiler sourc e category includes boilers used in manufacturing, processing, mining, refining, or any other industry. The commercial boiler source category includes**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **180** of **255** boilers used in commercial establishments such as stores/malls, laundries, apartments, restaurants, thea tres, and hotels/motels. The institutional boiler source category includes boilers used in medical centers (e.g., hospitals, clinics, nursing homes), educational and religious facilities (e.g., schools, universities, places of worship), and municipal buil dings (e.g., courthouses, arts centers, prisons). There are approximately 9 2 ,000 facilities affected by this final rule , most of which are small entities. By the defined nature of the category, m any of these sources are located in close proximity to resi dential areas, commercial centers, and other locations where large numbers of people live and work. Due to the large number of these sources, their nation

- wide dispersal, and the absence of site specific coordinates, EPA is unable to examine the distribut ions of exposures and health risks attributable to these sources among different socio

demographic groups for this rule, or to relate the locations of expected emission reductions to the locations of current poor air quality. However, this final rule is a nticipated to have substantial emissions reductions of toxic air pollutants ( s ee Table 2 of this preamble ), some of which are potential carcinogens, neurotoxins, and respiratory irritants. This final**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **181** of **255** rule will also result in reductions in criteria polluta nts such as CO, PM, SO 2, as well as ozone precursors. Because of the close proximity of these source categories to people, the substantial emission reductions of air toxics resulting from the implementation of this rule is anticipated to have health benef its for all persons living or going near these types of sources. (Please refer to the RIA for this rulemaking, which is available in the docket.) For example, there will be reductions of mercury emissions which will reduce potential exposures due to the atmospheric deposition of mercury for populations such as subsistence fisherman. In addition, there will be reductions in other air toxics which can cause adverse health effects such as ozone precursors that contribute to “smog.” EPA has determined that t his rule will not have disproportionately high and adverse human health or environmental effects on minority or low

- income populations because it increases the level of environmental protection for all affected populations without having any disproportion ately high and adverse human health or environmental effects on any population, including any minority, low

- income, or Tribal populations. EPA defines “Environmental Justice” to include meaningful**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **182** of **255** involvement of all people regardless of race, color, nati onal origin, or income with respect to the development, implementation, and enforcement of environmental laws, regulations, and polices. To promote meaningful involvement, EPA has developed a n EJ communication strategy to ensure that interested communitie s have access to this rule, are aware of its content, and have an opportunity to comment

. In addition,
S tate and F ederal permitting requirements will provide S tate and local governments and communities the opportunity to provide their comments on the perm it conditions associated with permitting these sources.
K. The Congressional Review Act, 5 U.S.C. 801 et seq., as added by the Small Business Regulatory Enforcement Fairness Act of 1996, generally provides that before a rule may take effect, the agency promulgating this final rule must submit a rule report, which includes a copy of this final rule , to each House of the Congress and to the Comptroller General of the United
S tates. EPA will submit a report containing this rule and other required information to the U.S. Senate, the U.S. House of Representatives, and the Comptroller General of the United States prior to publication of this final rule in the Federal Congressional Review Act**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **183** of **255** Register. A m ajor rule cannot take effect until 60 days after it is p ublished in the Federal Register

. This action is a “major rule” as defined by 5 U.S.C. 804(2). This rule will be effective [ INSERT THE DATE 6 0 DAYS FOLLOWING PUBLICATION IN THE
FEDERAL REGISTER ]

.**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **184** of **255** List of Subjects in 40 CFR part 63 Environmental protect ion, Administrative practice and procedure, Air pollution control, Hazardous substances, Intergovernmental relations, Incorporation by reference, Reporting and recordkeeping requirements.

______________________ Dated:

_______________________ Lisa P. Jackson , Administrator

.**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **185** of **255**
For the reasons stated in the preamble, title 40, chapter I, part 63 of the Code of Federal Regulations is proposed to be amended as follows: **PART 63 —**  **- [AMENDED]**  1. The authority citation for part 63 continues to read as follows : **Authority** : 42 U.S.C. 7401 et seq . **Subpart A —**  **[AMENDED]** 2. Section 63.14 is amended by revising paragraphs (b) (27), (b)(39), (b)(47), (b)(49), (b)(50), (b)( 5 2 ) , (b)(55), (b)(56), (b)(58), (b)(61), (b) (62) , and (i)(1) to read as follows: §63.14 Incorp oration by reference.

* * * * * (b) * * * (39) ASTM Method D388

- 05 , Standard Classification of Coals by Rank 1 , IBR approved for §63.7575 and §63.11237.

* * * * * (41) ASTM Method D1835

– 05, Standard Specification for Liqu e fied Petroleum (LP) Gases, 1 IBR approved for §63.7575 and §63.11237 .

* * * * ***Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **186** of **255** (58) ASTM D3173

– 03 (2008) , Standard Test Method for Moisture in the Analysis Sample of Coal and Coke, IBR approved for Table 6 to subpart DDDDD and Table 5 to subpart JJJJJJ of this part.

* * * * * (61) ASTM D6722

– 01 (2006) , Standard Test Method for Total Mercury in Coal and Coal Combustion Residues by the Direct Combustion Analysis, IBR approved for Table 6 to subpart DDDDD and Table 5 to subpart JJJJJJ of this part. (62) ASTM D5865

– 10a , Standard Test Method for Gross Calorific Value of Coal and Coke, IBR approved for Table 6 to subpart DDDDD and Table 5 to subpart JJJJJJ of this part.
* * * * * 3 . Part 63 is amended by adding subpart JJJJJJ to read as follows: **Subpart JJJJJJ --**  **National Emission S tandards for Hazardous Air**  **Pollutants for Industrial, Commercial, and Institutional Boilers Area Sources** 
Sec. **What this Subpart Covers** 63.11193 Am I subject to this subpart? 63.11194 What is the affected source of this subpart? 63.11195 Are any boilers not subject to this subpart? 63.11196 What are my compliance dates? **Emission Limits, Work Practice Standards, Emission Reduction Measures, and Management Practices** **Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **187** of **255**

63.11200 What are the subcategories of boilers? 63.11201 What standards must I mee t? **Initial Compliance Requirements** 63.11205 What are my general requirements for complying with this subpart? 63.11210 What are my initial compliance requirements and by what date must I conduct them? 63.11211 How do I demonstrate initial compliance wit h the emission limits? 63.11212 What stack tests and procedures must I use for the performance tests? 63.11213 What fuel analyses and procedures must I use for the performance tests? 63.11214 How do I demonstrate initial compliance with the work practice standard, emission reduction measures, and management practice? **Continuous Compliance Requirements** 63.11220 When must I conduct subsequent performance tests? 63.11221 How do I monitor and collect data to demonstrate continuous compliance? 63.11222 How do I demonstrate continuous compliance with the emission limits? 63.11223 How do I demonstrate continuous compliance with the work practice standards and management practices ? 63.11224 What are my monitoring, installation, operation, and maintenance require ments? 63.11225 What are my notification, reporting, and recordkeeping requirements? § 63.1122 6 How can I assert an a ffirmative d efense if I e xceed an e mission l imit d uring a m alfunction ? **Other Requirements and Information** 63.11235 What parts of the Gen eral Provisions apply to me? 63.11236 Who implements and enforces this subpart? 63.11237 What definitions apply to this subpart? Table 1 to Subpart JJJJJJ of Part 63. Emission Limits Table 2 to Subpart JJJJJJ of Part 63. Work Practice Standards Table 3 to Subpart JJJJJJ of Part 63. Operating Limits for**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **188** of **255** Boilers With Emission Limits Table 4 to Subpart JJJJJJ of Part 63. Performance (Stack) Testing Requirements Table 5 to Subpart JJJJJJ of Part 63. Fuel Analysis Requirements Table 6 to Subpart JJJJJJ of Part 63. Applicability of General Provisions to Subpart JJJJJJ

**Subpart JJJJJJ --**  **National Emission Standards for Hazardous Air Pollutants for Industrial, Commercial, and Institutional Boilers** 
**Area Sources What this Subpart Covers**  §63.11193 Am I subject t o this subpart? You are subject to this subpart if you own or operate an industrial, commercial, or institutional boiler as defined in §63.11237 that is located at, or is part of, an area source of haza rdous air pollutants (HAP), as defined in §63. 2, except as specified in §63 .11195. §63.11194 What is the affected source of this subpart ? (a) This subpart applies to each new , reconstr ucted, or existing affected source as defined in paragraphs (a)(1) and (2) of this section. (1) The affected source is the collection of all existing industrial, commercial, and institutional boilers within a subcategory , as listed in §63. 11200 and defin ed in §63. 11237,**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **189** of **255** located at an area source. (2) The affected source of this subpart is each new or reconstructed industrial, commercial, or institutional boiler within a subcategory, as listed in §63. 11200 and as defined in §63.11237, located at an area source. (b) An affected source is an existing source if you commenced construction or reconstruction of the affected source on or before June 4, 2010. (c) An affected source is a new source if you commenced construction or reconstruction of the affecte d source after June 4, 2010
. (d) A boiler is a new affected source if you commenced fuel switching from natural gas to solid fossil fuel, biomass, or liquid fuel after June 4, 2010

. ( e ) Any source that was a major source and installed a control device on a boiler after November 15, 1990, and, as a result, became an area source under 40 CFR part 63 is required to obtain a permit under 40 CFR part 70 or 40 CFR part 71. Otherwise, you are exempt from the obligation to obtain a permit under 40 CFR part 70 or 40 CFR part 71, provided you are not otherwise required by law to obtain a permit under 40 CFR 70.3(a) or 40 CFR 71.3(a). Notwithstanding the previous**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **190** of **255** sentence, you must continue to comply with the provisions of this subpart. §63.11195 Are any boiler s not subject to this subpart ? The types of boilers listed in paragraphs (a) through (e) of this section are not subject to this subpart. (a) Any boiler specifically listed as, or included in the definition of , an affected source in another standard(s ) under this part. (b) Any boiler specifically listed as an affected source in another standard(s) established under section 129 of the Clean Air Act (CAA). (c) A boiler required to have a permit under section 3005 of the Solid Waste Disposal Act or covered by subpart EEE of this part (e.g., hazardous waste boilers). (d) A boiler that is used specifically for research and development. This exemption does not include units that solely or primarily provide steam (or heat) to a process or for heating at a research and development facility. This exemption does not prohibit the use of the steam (or heat) generated from the boiler during research and development, however, the boiler must be concurrently and primarily engaged in research and development f or the exemption to apply.**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **191** of **255** (e) A gas

- fired boiler as defined in this subpart. (f) A hot water heater as defined in this subpart. (g) Any boiler that is used as a control device to comply with another subpart of this part, provided that at least 50 percent of the heat input to the boiler is provided by the gas stream that is regulated under another subpart. §63.11196 What are my compliance dates? (a) If you own or operate an existi ng affected source, you must achieve compliance with the applicable provisions in this subpart as specified in paragraphs (a)(1) through (a)(3) of this section. (1) If the existing affected boiler is subject to a work practice or management practice stan dard of a tune

- up, you must achieve compliance with the work practice standard no later than [INSERT THE DATE 1 YEARS AFTER PUBLICATION IN THE FEDERAL REGISTER]. (2) If the existing affected boiler is subject to emission limits, you must achieve complian ce with the emission limits no later than [INSERT THE DATE 3 YEARS AFTER PUBLICATION IN THE FEDERAL REGISTER]. (3) If the existing affected boiler is subject to the energy assessment requirement, you must achieve compliance with**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **192** of **255** the energy assessment req uirement no later than [INSERT THE DATE 3 YEARS AFTER PUBLICATION IN THE FEDERAL REGISTER]. (b) If you start up a new affected source on or before [INSERT THE DATE 60 DAYS AFTER THE DATE OF PUBLICATION IN THE FEDERAL REGISTER], you must achieve complianc e with the provisions of this subpart no later than [INSERT THE DATE 60
DAYS AFTER THE DATE OF PUBLICATION IN THE FEDERAL REGISTER]. (c) If you start up a new affected source after [INSERT
THE DATE 60 DAYS AFTER THE DATE OF PUBLICATION IN THE FEDERAL
REG ISTER], you must achieve compliance with the provisions of this subpart upon startup of your affected source. (d ) If you own or operate an industrial, commercial, or institutional boiler and would be subject to this subpart except for the exemption in §63. 11195(b) for commercial and industrial solid waste incineration units covered by 40 CFR part 60, subpart CCCC or subpart DDDD, and you cease combusting solid
waste , you must be in compliance with this subpart on the effective date of the waste to fuel swit ch , if the effective date of that switch is after the applicable compliance date in paragraphs (a)

- (c) of this section . The effective date of the waste to fuel switch is a date selected by you consistent with**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **193** of **255** part 60, subpart CCCC or subpart DDDD that mus t be at least 12 months from the date that you ceased combusting solid waste. **Emission Limits, Work Practice Standards, Emission Reduction Measures, and Management Practices**  §63.11200 What are the subcategories of boilers ? The subcategories of boilers are coal , biomass, and liquid fuel. Each subcategory is defined in §63.11237. §63.11201 What standards must I meet ? (a) You must comply with each emission limit specified in Table 1 of this subpart that applies to your boiler. (b) You must comply with each work practice standard, emission reduction measure, and management practice specified in Table 2 of this subpart that applies to your boiler

. An energy assessment completed on or after January 1, 2008 that meets the requirements in Table 2 shall satisfy the energy assessmen t portion of this requir ement. (c) You must comply with each operating limit specified in Table 3 of this subpart that applies to your boiler

. (d) These standards apply at all times. **General C**  **ompliance Requirements** §63.11205 What are my general requirements for complying wit h this subpart?**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **194** of **255** (a) 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. The general duty to minimize emissions does not require you to make any further efforts to reduce emissions if levels required by this standard have been achieved. Determination of whether such operation and maintenance procedures are being us ed will be based on information available to the Administrator which may include, but is not limited to, monitoring results, review of operation and maintenance procedures, review of operation and maintenance records, and inspection of the source. (b) Yo u can demonstrate compliance with any applicable mercury emission limit using fuel analysis if the emission rate calculated according to §63.11211(b) is less than the applicable emission limit. Otherwise, you must demonstrate compliance using stack testin g. **Initial C**  **ompliance Requirements** §63.11210 What are my initial compliance requirements and by what date must I conduct them ? (a) You must demonstrate initial compliance with each**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **195** of **255** emission limit specified in Table 1 of this subpart that applies to you by either conducting performance (stack) tests, as applicable, according to §63.11212 and Table 4 of this subpart or, for mercury, conducting fuel analyses, as applicable, according to §63.11213 and Table 5 to this subpart. (b) For existing affected sour ces that have applicable emission limits, you must demonstrate initial compliance no later than 180 days after the compliance date that is specified in §63.11196 and according to the applicable provisions in §63.7(a)(2). (c) For existing affected sources that have applicable work practice standards, management practices, or emission reduction measures, you must demonstrate initial compliance no later than the compliance date that is specified in §63.11196 and according to the applicable provisions in §63. 7(a)(2). (d) For new or reconstructed affected sources, you must demonstrate initial compliance no later than 180 calendar days after [INSERT THE DATE OF PUBLICATION IN THE FEDERAL REGISTER] or within 180 calendar days after startup of the source, whiche ver is later, according to §63.7(a)(2)(ix). (e ) For affected sources that ceased burning solid waste consistent with §63. 11196(d), you must demonstrate compliance**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **196** of **255** within 60 days of the effective date of the waste to fuel switch. You must complete all ini tial compliance demonstrations before you commence or recommence combustion of solid waste. §63.11211 How do I demonstrate initial compliance with the emission limits? (a) For affected sources that demonstrate compliance with any of the emission limits of this subpart through performance (stack) testing, your initial compliance requirements include conducting performance tests accor ding to §63.11212 and Table 4 to this subpart , conducting a fuel analysis for each type of fuel burned in your boiler according to §63.11213 and Table 5 to this subpart, establishing operating limits according to §63.11222, and conducting continuous monito ring system ( CMS ) performance evaluations according to §63.11223. For affected boiler s that burn a single type of fuel, you are exempted from the compliance requirements of conducting a fuel analysis for each type of fuel burned in your boiler. For purp oses of this subpart, boiler s that use a supplemental fuel only for startup, unit shutdown, and transient flame stability purposes still qualify as affected boilers that burn a single type of fuel, and the supplemental fuel is not subject to the fuel analy sis requirements under §63. 11213 and Table 5
.**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **197** of **255** (b) If you elect to demonstrate compliance with an applicable mercury emission limit through fuel analysis, you must conduct fuel analyses according to §63.11213 and Table 5 and follow the procedures in parag raphs (b)(1) through (3) of this section. (1) If you burn more than one fuel type, you must determine the fuel type you could burn in your boiler that would result in the maximum emission rates of mercury. (2) You must determine the 90th percentile co nfidence level fuel mercury concentration of the composite samples analyzed for each fuel type using Equation 1 of this section.

P 90 = mean + (SD * t) (Eq. 1) Where:
P 90 = 90th percentile confidence level mercury concentration, in pounds per million Btu; mean = Arithmetic average of the fuel mercury concentration in the fuel samples analyzed according to §63.11213, in units of pounds per million Btu; SD = Standard deviation of the mercury concentration in the fuel samples analyzed according to §63.11213, in units of pounds per million Btu; 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 com pliance with the applicable mercury**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **198** of **255** emission limit, the emission rate that you calculate for your boiler using Equation 1 of this section must be less than the applicable mercury emission limit. §63.11212 What stack tests and procedures must I use for th e performance tests? (a) You must conduct all performance tests according to §63.7 (c), (d), (f), and (h)

. You must also develop a site

specific test plan according to the requireme nts in §63.7(c). (b) You must conduct each stack test according to the requirements in Table 4 to this subpart. (c) You must conduct performance stack tests at the maximum normal operating load while burning the type of fuel or mixture of fuels that have the highest emissions potential for each regulated pollutant, and you must demonstrate initial compliance based on these performance stack tests. For subcategories with more than one emission limit, these requirements could result in the need to cond uct more than one performance stack test. Following each performance stack test and until the next performance stack test, you must comply with the operating limit for operating load conditions specified in Table 3 to this subpart. (d) You must conduct a minimum of three separate test runs**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **199** of **255** for each performance test required in this section, as specified in §63.7(e)(3). The sampling time for each test run must last at least 1 hour except that the sampling time for the test runs conducted for mercury emis sions must last at least 2 hours. (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 of appendix A to part 60 of this chapter to convert the measured PM con centrations and the measured mercury concentrations that result from the initial performance test to pounds per million Btu heat input emission
rates. §63.11213 What fuel analyses and procedures must I use for the performance tests ? (a) You must condu ct fuel analyses according to the procedures in paragraphs (b) and (c) of this section and Table 5 to this subpart, as applicable. You are not required to conduct fuel analys es for fuel s used for only startup, unit shutdown, and transient flame stability purposes . (b) At a minimum, you must obtain three composite fuel samples for each fuel type according to the procedures in Table 5 of this subpart. Each composite sample will consist of a minimum of three samples collected at approximately equal**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **200** of **255** interva ls during a test run period. (c) Determine the concentration of mercury in the fuel in units of pounds per million Btu of each composite sample for each fuel type according to the procedures in Table 5 to this subpart. §63.1121 4 How do I demonstrate i nitial compliance with the work practice standard, emission reduction measures, and management practice ? (a) If you own or operate an existing or new coal

- fired boiler with a heat input capacity of less than 10 million Btu per hour, you must conduct a per formance tune

- up according to §63. 11223(b) and you must submit a signed statement in the Notification of Compliance Status report that indicates that you conducted a tune

- up of the boiler. (b) If you own or operate a n existing or new biomass

- fired boiler or a n existing or new liquid fuel

- fired boiler, you must conduct a performance tune

- up according to §63.11223(b) and you must submit a signed statement in the Notification of Compliance Status report that indicates that you conducted a tune

- up of the boile r. (c) If you own or operate an existing affected boiler with a heat input capacity of 10 million Btu per hour or greater, you**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **201** of **255** must submit the energy assessment report, along with a signed certification that the assessment is an accurate depiction of
your facility. **Continuous Compliance Requirements** §63.11220 When must I conduct subsequent performance tests? (a) If your boiler has a heat input capacity of 10 million
Btu per hour or greater, you must conduct all a pplicable performance (stack) tests according to §63.11212 on an annual basis, unless you follow the requirements listed in paragraphs (b) through (d) of this section. Annual performance tests must be completed between 1 1 and 1 3 months after the previous performance test, unless you follow the requirements listed in paragraphs (b) through (d) of this section. (b) You can conduct performance stack tests less often for particulate matter or mercury if your performance stack tests for the pollutant for at least 3 consecutive years show that your emissions are at or below 75 percent of 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. In this case, you do not have to conduct a performance stack test for that pollutant for the next 2 years. You must conduct a performance stack test during the third year**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **202** of **255** and no more than 3 7 months after the previous performance stack
test. (c) If your boiler continues to meet the emission limit for particulate matter or mercury , you may choose to conduct performance stack tests for the pollutant every third year if your emissions are at or below 75 percent of the emission limit, and if there are no changes in the operatio n of the affected source or air pollution control equipment that could increase emissions, but each such performance stack test must be conducted no more than 36 months after the previous performance
test . (d) If a performance stack test shows emissions e xceeded 75 percent of the emission limit, you must conduct annual performance stack tests for that pollutant until all performance stack tests over a consecutive 3

- year period show compliance at or below 75 percent of the limit

. (e) If you have an applic able CO emission limit, you must conduct annual performance tests for CO according to §63.11211. Each annual performance test must be conducted between 1 1 and 1 3 months after the previous performance test. (f) If you demonstrate compliance with the me rcury emission limit based on fuel analysis, you must conduct a fuel**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **203** of **255** analysis according to §63.11213 for each type of fuel burned monthly. If you plan to burn a new type of fuel or fuel mixture, you must conduct a fuel analysis before burning the new type of fuel or mixture in your boiler. You must recalculate the mercury emission rate using Equation 1 of §63.11211. The recalculated mercury emission rate must be less than the applicable emission limit. §63.11221 How do I monitor and collect data to demo nstrate continuous compliance? ( a ) You must monitor and collect data according to this section. ( b ) You must operate the monitoring system and collect data a t all required intervals at all times the affected source is operating except for periods of monitoring system malfunctions
or out

- of

- control periods, repairs associated with monitoring system malfunctions or out

- of

- control periods (see section 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 pr eventable failure of the monitoring system to provide valid data. Monitoring system failures that**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **204** of **255** are caused in part by poor maintenance or careless operation are not malfunctions. You are required to effect monitoring system repairs in response to monit oring system malfunctions or out

- of

control periods 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 w ith 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 requi red 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. §63.11222 How do I d emonstrate continuous compliance with the emission limits?**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **205** of **255** (a) You must demonstrate continuous compliance with each emission limit and operating limit in Tables 1 and 3 to this subpart that applies to you according to paragraphs (a)(1) through ( 5 ) of this section. (1) Following the date on which the initial compliance demonstration is completed or is required to be completed under §§63 .7 and 63.11196, 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 3 to this subpart. Operation above the established maximum or be low the established minimum operating limits shall constitute a deviation of established operating limits. Operating limits are confirmed or reestablished during performance tests. (2) If you have an applicable mercury or PM emission limit, you must kee p records of the type and amount of all fuels burned in each boiler during the reporting period to demonstrate that all fuel types and mixtures of fuels burned would result in lower emissions of mercury than the applicable emission limit. (3) If you have an applicable mercury emission limit and you plan to burn a new type of fuel, you must determine the mercury concentration for any new fuel type in units of pounds**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **206** of **255** per million Btu, using the procedures in Equation 1 based on supplier data or your own fuel analysis and meet the requirements in paragraphs (a)(3)(i) or (ii) of this section. (i) The recalculated mercury emission rate must be less than the applicable emission limit. (ii) If the mercury concentration is higher than mercury fuel input during t he 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 §63.11212 to demonstrate that the mercury emissions do not exceed the emission limit. (4) 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 operate and maintain the fabric filte r system such that the alarm does not sound more than 5 percent of the operating time during a 6

- month period. You must also keep records of the date, time, and duration of each alarm, the time corrective action was initiated and completed, and a brief de scription of the cause of the alarm and the corrective action taken. You must also record the percent of the operating time during each 6

- month period that the alarm**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **207** of **255** sounds. In calculating this operating time percentage, if inspection of the fabric filte r 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 co unted as the actual amount of time taken to initiate corrective action. (b) You must report each instance in which you did not meet each emission limit and operating limit in Tables 1 and 3 to this subpart that apply to you. These instances are deviatio ns from the emission limits in this subpart. These deviations must be reported according to the requirements in §63.1122 5
. §63.11223 How do I demonstrate continuous compliance with the work practice and management practice standards? (a) For affected sources subject to the work practice standard or the management practices of a tune

- up , you must conduct a biennial performance tune

- up ac cording to §63. 11223(b) and keep records as required in §63.1122 5 (c) to demonstrate continuous compliance. Each biennial tune

- up must be conducted between 23 and 25 months after the previous tune

- up . (b) You must conduct a tune

- up of the boiler biennial ly to**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **208** of **255** demonstrate continuous compliance as specified in paragraphs (b)(1) through (6) of this section. (1) Inspect the burner, and clean or replace any components of the burner as necessary; (2) Inspect the flame pattern and make any adjustments to the burner necessary to optimize the flame pattern consistent with the manufacturer’s specifications; (3) Inspect the system controlling the air

- to

- fuel ratio, and ensure that it is correctly calibrated and functioning properly; (4) Opt imize total emissio ns of CO consistent with the manufacturer’s specifications; (5) Measure the concentration in the effluent stream of CO in parts per million, by volume, dry basis (ppmvd), before and after the adjustments are made; and (6) Maintain on

- site and submit, i f requested by the Administrator, a biennial report containing the information in paragraphs (b)(6)(i) through (iii) of this section, (i) The concentrations of CO in the effluent stream in ppmvd, and oxygen in percent dry basis, measured before and after the tune

- up of the boiler as defined in §63.11222(b) of this section ;**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **209** of **255** (ii) A description of any corrective actions taken as a part of the tune

- up of the boiler as defined in §63.11222(b) of this section ; and (iii) The type and amount of fuel used over the 12 months prior to the biennial tune

- up of the boiler as defined in §63.11222(b) of this section

. ( c ) If you own or operate an existing or new coal

- fired boiler with a heat input capacity of 10 million Btu per hour or greater , you must minimize the b oiler’s time spent during startup and shutdown following the manufacturer’s recommended procedures and you must submit a signed statement in the Notification of Compliance Status report that indicates that you conducted startups and shutdowns according to the manufacturer’s recommended procedures

. §63.11224 What are my monitoring, installation, operation, and maintenance requirements? (a) If you are usin g a control device to comply with the emission limits specified in Table 1 of this subpart, you must maintain each operating limit in Table 3 of this subpart that applies to your boiler. If you use a control device not covered in Table 3, or you wish to e stablish and monitor an alternative operating limit and alternative monitoring parameters, you must**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **210** of **255** apply to the United States Environmental Protection Agency (EPA) Administrator for approval of alternative monitoring under §63.8(f). (b) If you demonstra te compliance with any applicable emission limit through stack testing and subsequent compliance with operating limits , you must develop a site

- specific monitoring plan according to the requirements in paragraphs (b)(1) through (4) of this section. This r equirement also applies to you if you petition the EPA Administrator for alternative monitoring parameters under §63.8(f). (1) For each continuous monitoring system (CMS) required in this section, you must develop, and submit to the EPA Administrator for approval upon request, a site

- specific monitoring plan that addresses paragraphs (b)(1)(i) through (iii) of this section. You must submit this site

- specific monitoring plan (if requested) at least 60 days before your initial performance evaluation of you r CMS. (i) Installation of the CMS sampling probe or other interface at a measurement location relative to each affected unit such that the measurement is representative of control of the exhaust emissions (e.g., on or downstream of the last control devi ce);**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **211** of **255** (ii) Performance and equipment specifications for the sample interface, the pollutant concentration or parametric signal analyzer, and the data collection and reduction systems; and (iii) Performance evaluation procedures and acceptance criteria ( e.g., calibrations). (2) In your site

- specific monitoring plan, you must also address paragraphs (b)(2)(i) through (iii) of this section. (i) Ongoing operation and maintenance procedures in accordance with the general requirements of §63.8(c)(1), (3), and (4)(ii); (ii) Ongoing data quality assurance procedures in accordance with the general requirements of §63.8(d); and (iii) Ongoing recordkeeping and reporting procedures in accordance with the general requirements of §63.10(c), (e)(1), and (e)(2)(i ). (3) You must conduct a performance evaluation of each CMS in accordance with your site

- specific monitoring plan. (4) You must operate and maintain the CMS in continuous operation according to the site

- specific monitoring plan. (c) If you have an o perating limit that requires the use of a CMS, you must install, operate, and maintain each**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **212** of **255** continuous parameter monitoring system (CPMS) according to the procedures in paragraphs (c)(1) through (5) of this section. (1) The CPMS must complete a minimum o f one cycle of operation for each successive 15

- minute period. You must have a minimum of four successive cycles of operation to have a valid hour of data. (2) Except for monitoring malfunctions, associated repairs, and required quality assurance or con trol activities (including, as applicable, calibration checks and required zero and span adjustments), you must conduct all monitoring in continuous operation at all times that the unit is operating. A monitoring malfunction is any sudden, infrequent, not reasonably preventable failure of the monitoring to provide valid data. Monitoring failures that are caused in part by poor maintenance or careless operation are not malfunctions. (3) For purposes of calculating data averages, you must not use data rec orded during monitoring malfunctions, associated repairs, out of control periods, or required quality assurance or control activities. You must use all the data collected during all other periods in assessing compliance. Any period for which the monitori ng system is out

- of

- control and data are not available for a required calculation constitutes a deviation**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **213** of **255** from the monitoring requirements. (4) Determine the 4

- hour block average of all recorded readings, except as provided in paragraph (c)(3) of this

se ction. (5) Record the results of each inspection, calibration, and validation check. (d) If you have an applicable opacity operating limit under this rule , you must install, operate, certify and maintain each continuous opacity monitoring system (COMS) according to the procedures in paragraphs (d)(1) through (7) of this section by the compliance date specified in §63.11196. (1) Each COMS must be installed, operated, and maintained according to PS 1 of 40 CFR part 60, appendix B. (2) You must conduct a performance evaluation of each COMS according to the requirements in §63.8 and according to PS 1 of 40 CFR part 60, appendix B. (3) As specified in §63.8(c)(4)(i), each COMS must complete a minimum of one cycle of sampling and analyzing for each succe ssive 10

- second period and one cycle of data recording for each successive 6

- minute period. (4) The COMS data must be reduced as specified in §63.8(g)(2).**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **214** of **255** (5) You must include in your site

- specific monitoring plan procedures and acceptance criteria for operating and maintaining each COMS according to the requirements in §63.8(d). At a minimum, the monitoring plan must include a daily calibration drift assessment, a quarterly performance audit, and an annual zero alignment audit of each COMS. (6) You m ust operate and maintain each COMS according to the requirements in the monitoring plan and the requirements of §63.8(e). Identify periods the COMS is out of control including any periods that the COMS fails to pass a daily calibration drift assessment, a quarterly performance audit, or an annual zero alignment audit. (7) You must determine and record all the 1

- hour block averages collected for periods during which the COMS is not out of control. ( e ) If you use a fabric filter bag leak detection system to comply with the requirements of this subpart, you must install, calibrate, maintain, and continuously operate the bag leak detection system as specified in paragraphs ( e )(1) through (8) of this section. (1) You must install and operate a bag leak detec tion system for each exhaust stack of the fabric filter.**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **215** of **255** (2) Each bag leak detection system must be installed, operated, calibrated, and maintained in a manner consistent with the manufacturer's written specifications and recommendations and in accordance with EPA Fabric Filter Bag Leak Detection Guidance, EPA

– 454/R

– 98

– 015, September 1997 (incorporated by reference, see § 63.14)
. (3) The bag leak detection system must be certified by the manufacturer to be capable of detecting particulate matter emissions at concentrations of 10 milligrams per actual cubic meter or less. (4) The bag leak detection system sensor must provide output of relative or absolute particulate matter loadings. (5) The bag leak detection system must be equipped with a device to conti nuously record the output signal from the sensor. (6) The bag leak detection system must be equipped with an audible or visual alarm system that will activate automatically when an increase in relative particulate matter emissions over a preset level is d etected. The alarm must be located where it is easily heard or seen by plant operating personnel. (7) For positive pressure fabric filter systems that do not duct all compartments of cells to a common stack, a bag leak**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **216** of **255** detection system must be installed in each baghouse compartment or cell. (8) Where multiple bag leak detectors are required, the system's instrumentation and alarm may be shared among detectors. § 63.11225 What are my notification, reporting, and recordkeeping, requirements ? (a) You must submit the notifications specified in paragraphs (a)(1) through (a)( 5 ) of this section. (1) You must submit all of the notifications in §§63.7(b): 63.8(e) and (f); 63.9(b) through (e); and 63.9(g) and (h) that apply to you by the dates specified in those sections. (2) As specified in §63.9(b)(2), you must submit the Initial Notification no later than 120 calendar days after [INSERT THE DATE 60 DAYS AFTER THE DA TE OF PUBLICATION IN TH E
FEDERAL REGISTER ] or within 120 days after the source becomes subject to the standard. (3 ) If you are required to conduct a performance stack
t est you must submit to the delegated authority a Notification of Intent to conduct a performance test at least 6 0 days before the performance stack test is scheduled to begin. ( 4 ) You must submit the Notification of Compliance Status**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **217** of **255** in accordance with §63.9(h) no later than 120 days after the applicable compliance date specified in §63.11196 unless you must conduct a performance stack test. If you must conduct a performance stack test, you must submit the Notification of Compliance Status within 60 days of completing the performance stack test. In addition to the information required in §63.9(h)(2), your notification must include the following certification(s) of compliance, as a pplicable, and signed by a responsible official: (i) “This facility complies with the requirements in §63.112 14 (b) to conduct a n initial tune

- up of the boiler”. (ii) “This facility has had an energy assessment performed according to §63.11215.” (iii) This certification of compliance by the owner or operator that installs bag leak detection systems: “This facility has prepared a bag leak detection system monitoring plan in accordance with §63.11221 and will operate each bag leak detection system accor ding to the plan.” ( i v ) For units that do not qualify for a statutory exemption as provided in section 129(g)(1) of the Clean Air Act: “No secondary materials that are solid waste were combusted in any affected unit.”**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **21 8**  of **255** ( 5 ) If you are using data from a previously conducted emission test to serve as documentation of conformance with the emission standards and operating limits of this subpart consistent with § 63.7(e)(2)(iv), you must submit the test data in lieu of the initial performance test results wit h the Notification of Compliance Status required under paragraph (a)( 4 ) of this section. (b) You must prepare, by March 1 of each year, an annual compliance certification report for the previous calendar year containing the information specified in paragr aphs (b)(1) through (b)( 4 ) of this section. You must submit the report by March 15 if you had any instance described by paragraph (b)( 4 ) of this section. (1) Company name and address. (2) Statement by a responsible official, with the official’s name, t itle, phone number, e

- mail address, and signature, certifying the truth, accuracy and completeness of the notification and a statement of whether the source has complied with all the relevant standards and other requirements of this subpart. (3) If the so urce is not in compliance, include a description of deviations from the applicable requirements, the**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **219** of **255** time periods during which the deviations occurred, and the corrective actions taken. (4) The total fuel use by each affected source subject to an emission limit, for each calend ar month within the reporting period, including, but not limited to, a description of the fuel, including whether the fuel has received a non

- waste determination by you or EPA, and the total fuel usage amount with units of measure. ( c) You must maintain the records specified in paragraphs (c)(1) through (5) of this section. (1) As required in §63.10(b)(2)(xiv), you must keep a copy of each notification and report that you submitted to comply with this subpart and all documentation supporting any Initial Notification or Notification of Compliance Status that you submitted. (2) You must keep records to document conformance with the work practices, emission reduction measures, and management practices required by §63.1121 4 as specifi ed in paragraphs (c)(2)(i) and (i i ) of this section. (i) Records must identify each boiler, the date of tune

up, the procedures followed for tune

- up, and the manufacturer’s specifications to which the boiler was tuned.**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **220** of **255** (ii) Records documenting monthly fuel use by each boiler, including the type(s) of fuel , including, but not limited to, a description of the fuel, including whether the fuel has received

a non - waste determination by you or EPA, and the total fuel usage amount with units of measure. If yo u combust non

hazardous secondary materials that have been determined not to be solid waste pursuant to §41.3(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 be en processed from a discarded non

- hazardous secondary material pursuant to §241.3(b)(2), you must keep records as to how the operations that produced the fuel satisfies the definition of processing in §241.2. If the fuel received a non

- waste determination pursuant to the petition process submitted under §241.3(c), you must keep a record that documents how the fuel satisfies the requirements of the petition process. (3) For sources that demonstrate compliance through fuel analysis, a copy of all calculati ons and supporting documentation that were done to demonstrate compliance with the mercury emission limits. Supporting documentation should include results of any fuel analyses. You can use the results from one fuel analysis for multiple boilers provided they are**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **221** of **255** all burning the same fuel type. (4) Records of the occurrence and duration of each malfunction of the boiler, or of the associated air pollution control and monitoring equipment.
( 5) Records of actions taken during periods of malfunction to min imize emissions in accordance with the general duty to minimize emissions in §63.11205(a), including corrective actions to restore the malfunctioning boiler, air pollution control, or monitoring equipment to its normal or usual manner of operation. ( 6 ) Y ou must keep the records of all inspection and monitoring data required by §§63.11221 and 63.11222 , and the information identified in paragraphs (c)( 6 )(i) through (vi) of this section for each required inspection or monitoring. (i) The date, place, and t ime of the monitoring event; (ii) Person conducting the monitoring; (iii) Technique or method used; (iv) Operating conditions during the activity; (v) Results, including the date, time, and duration of the period from the time the monitoring indica ted a problem to the time that monitoring indicated proper operation; and (v i ) Maintenance or corrective action taken (if applicable).**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **222** of **255** ( 7 ) If you use a bag leak detection system, you must keep the records specified in paragraphs (c)( 7 )(i) through (iii) of this section. (i) Records of the bag leak detection system output. (ii) Records of bag leak detection system adjustments, including the date and time of the adjustment, the initial bag leak detection system settings, and the final bag leak detection system settings. (ii i) The date and time of all bag leak detection system alarms, and for each valid alarm, the time you initiated corrective action, the corrective action taken, and the date on which corrective action was completed. (d) Your records must be in a form suitable and readily available for expeditious review, according to §63.10(b)(1). As specified in §63.10(b)(1), you must keep each record for 5 years following the date of each recorded action. You must keep each record onsite for at le ast 2 years after the date of each recorded action according to §63.10(b)(1). You may keep the records offsite for the remaining 3 years. ( e ) After December 31, 2011, within 60 days after the date of completing each performance evaluation or performance test, as defined in §63.2, conducted to demonstrate compliance with**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **223** of **255** this subpart, the owner or operator of the affected facility must submit relative accuracy test audit (i.e., reference method) data and performance test (i.e., compliance test) data , excep t opacity data, electronically to EPA’s Central Data Exchange (CDX) using the Electronic Reporting Tool (ERT) or other compatible electronic spreadsheet. Only data collected using methods compatible with the ERT are subject to this requirement to be submi tted electronically into EPA’s WebFIRE database. (f) If you intend to commence or recommence combustion of solid waste, you must provide 30 days prior notice of the date upon which you will commence or recommence combustion of solid
waste. The notificati on must identify: ( 1 ) The name of the owner or operator of the affected source, the location of the source, the boiler(s) or process heater(s) that will commence burning solid waste, and the date of the notice; (2 ) The currently applicable subcategory unde r this subpart;

(3) The date on which you became subject to the currently applicable emission limits;**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **224** of **255** (4 ) The date upon which you will commence combusting solid
waste. § 63.1122 6 How can I assert an a ffirmative d efense if I e xceed

an emission l imit d urin g a m alfunction ? In response to an action to enforce the standards set forth in paragraph § 63. 11201 you may assert an affirmative defense to a claim for civil penalties for exceedances of numerical emission limit s that are caused by malfunction, as defined at 40 CFR 63.2. Appropriate penalties may be assessed, however, if you fail to meet your burden of proving all of the requirements in the affirmative defense. The affirmative defense shall not be available for claims for injunctive relief. (a) To establ ish the affirmative defense in any action to enforce such a limit, you must timely meet the notification requirements in paragraph (b) of this section, and must prove by a preponderance of evidence that: (1) The excess emissions: (i) Were caused by a sudd en, short, 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**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **225** of **255** planning, proper design or bet ter 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 maintena nce; 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 durat ion of the excess emissions (including any bypass) were minimized to the maximum extent practicable during periods of such emissions; and (4) If the excess emissions resulted from a bypass of control equipment or a process, then the bypass was unavoida ble to prevent loss of life, severe 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 mon itoring and control systems were kept in operation if at all possible; and**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **226** of **255** (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 operate d in a manner consistent with good practices for minimizing emissions; and (9) A written root cause analysis has been prepared to determine, correct, and eliminate the primary causes of the malfunction and the excess emissions resulting from the malfunctio n event at issue. The analysis shall also specify, using best monitoring methods and engineering judgment, the amount of excess emissions that were the result of the malfunction. (b) Notification. The owner or operator of the facility experiencing an exceedance of its emission limit(s) during a malfunction shall notify the Administrator by telephone or facsimile (FAX) transmission as soon as possible, but no later than two business days after the initial occurrence of the malfunction, if it wishes to avail itself of an affirmative defense to civil penalties for that malfunction. The owner or operator seeking to assert an affirmative defense shall also submit a written report to the Administrator within 30 days of the initial occurrence of the exceedan ce of the standard in**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **227** of **255** § 63. 11201 to demonstrate, with all necessary supporting documentation, that it has met the requirements set forth in paragraph (a) of this section

. **Other Requirements and Information** §63.11235 What parts of the General Provisions apply to me? Table 6 to this subpart shows which parts of the General Provisions in §§63.1 through 63.15 apply to you. §63.11236 Who implements and enforces this subpart? (a) This subpart can be implemented and enforced by 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 h as the authority to implement and enforce this subpart. You should contact your EPA Regional Office to find out if implementation and enforcement of 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 contained in paragraphs (c) of this section are retained by the EPA Administrator and are not transferred to the State, local, or tri bal agency. (c) The authorities that cannot be delegated to State,**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **228** of **255** local, or tribal agencies are specified in paragraphs (c)(1) through (5) of this section. (1) Approval of an alternative non

- opacity emission standard and work practice standards in §63 .11223(a). (2) Approval of alternative opacity emission standard under §63.6(h)(9). (3) Approval of major change to test methods under §63.7(e)(2)(ii) and (f). A “major change to test method” is defined in §63.90. (4) Approval of a major change to m onitoring under §63.8(f). A “major change to monitoring” is defined in §63.90. (5) Approval of major change to recordkeeping and reporting under §63.10(f). A “major change to recordkeeping/reporting” is defined in §63.90. §63.11237 What definitions a pply to this subpart? Terms used in this subpart are defined in the CAA, in §63.2 (the General Provisions), and in this section as follows: Affirmative defense means, in the context of an enfo rcement 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.**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **229** of **255** Annual heat input basis means the 12 months preceding the compliance demonstration. Bag leak detection system means an instrument that is capable of monitoring particulate matter loadings in the exhaust of a fabric filter (i.e., baghouse) in order to detect bag failures. A bag leak detection system includes, but is not limited to, an instrument that operates on electrodynamic, triboelectric, light scattering, light transmittance, or other principle to monitor relative particulate matter loadings. Biomass means any biomas s - based solid fuel that is not a solid waste. This includes , but is not limited to, wood residue and wood products (e.g., trees, tree stumps, tree limbs, bark, lumber, sawdust, sanderdust, chips, scraps, slabs, millings, and shavings); animal manure, incl uding litter and other bedding materials ; vegetative agricultural and silvicultural materials, such as logging residues (slash), nut and grain hulls and chaff (e.g., almond, walnut, peanut, rice, and wheat), bagasse, orchard prunings, corn stalks, coffee b ean hulls and grounds. Biomass subcategory includes any boiler that burns at least 15 percent biomass on an annual heat input basis. Boiler means an enclosed device using controlled flame combustion in which water is heated to recover thermal energy in**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **230** of **255** the form of steam or hot water

. Controlled flame combustion refers to a steady

- state, or near steady

- state, process wherein fuel and/or oxidizer feed rates are controlled. Waste heat boilers are excluded from this definition. Boiler system means the b oiler and associated components, such as, the feedwater system, the combustion air system, the boiler fuel system (including burners), blowdown system, combustion control system, steam system, and condensate return system. Coal means all solid fuels clas sifiable as anthracite, bituminous, sub

- bituminous, or lignite by the American Society for Testing and Materials in ASTM D388

- 05, “Standard Classification of Coals by Rank 1 ” (incorporated by reference, see §63.14(b)), coal refuse, and petroleum coke. For the purposes of this subpart, this definition of “coal” includes synthetic fuels derived from coal including, but not limited to, solvent

refined coal, coal

- oil mixtures, and coal

- water mixtures. Coal derived gases are excluded from this definition. Coal subcategory includes any boiler that burns any solid fossil fuel and no more than 15 percent biomass on an annual heat input basis. Commercial boiler means a boiler used in commercial**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **231** of **255** establishments such as hotels, restaurants, and laundries to provide e lectricity, steam, and/or hot water. Deviatio n. (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 i ncluding, but not limited to, any emission limit, operating limit, or work practice standard; ( 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; or ( 2 ) A deviation is not always a violation. The determination of whether a deviation constitutes a violation of the standard is up to the discretion of the entity responsible for enforcement of th e standards. Dry scrubber means an add

- on air pollution control system that injects dry alkaline sorbent (dry injection) or sprays an alkaline sorbent (spray dryer) to react with and neutralize acid gas in the exhaust stream forming a dry powder material. Sorbent injection systems in fluidized bed boilers are included in this definition.**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **232** of **255** Electrostatic precipitator (ESP) means an add

- on air pollution control device used to capture particulate matter by charging the particles using an electrostatic field, collecting the particles using a grounded collecting surface, and transporting the particles into a hopper. Energy a ssessment means an in

- depth assessment of the boiler system(s) and the energy use system(s) at a facility to identify immediate and long

- ter m opportunities to save energy

. An energy assessment involves a thorough examination of potential savings from energy efficiency improvements, waste minimization and pollution prevention, and productivity improvement. Energy assessment means the followin g only as this term is used in Table 3 to this subpart.

a. Energy a ssessment for facilities with affected boilers using less than 0.3 trillion Btu (TBtu) per year heat input will be one day in length maximum. The boiler system and energy use system account ing for at least 50 percent of the affected boiler(s) energy output will be evaluated to identify energy savings opportunities, within the limit of performing a one day energy assessment. b. Energy a ssessment for facilities with affected boilers and process h eaters using 0.3 to 1 TBtu/year will be three days**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **233** of **255** in length maximum. The boiler system (s) and any energy use system (s) accounting for at least 33 percent of the affected boiler(s) energy output will be evaluated to identify energy savings o pportunities, within the limit of performing a 3 day energy assessment.

c. Energy a ssessment for facilities with affected boilers and process heaters using greater than 1 .0 TBtu/year, the boiler system (s) and any energy use system (s) accounting for at least 20 percent of t he affected boiler(s) energy output will be evaluated to identify energy savings opportunities. Energy use system includes, but not limited to, process heating; compressed air systems; machine drive (motors, pumps, fans); process cooling; facility heatin g, ventilation, and air

conditioning (HVAC) systems; hot heater systems;, building envelop; and lighting. Equivalent means the following only as this term is used in Table 5 to this subpart : (1) An equivalent sample collection procedure means a publishe d 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**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **234** of **255** minimum of three increments collected at approximately equal intervals over the test p eriod. (2) An equivalent sample compositing procedure means a published VCS or EPA method to systematically mix and obtain a representative subsample (part) of the composite sample. (3) An equivalent sample preparation procedure means a published VCS o r EPA method that: Clearly states that the standard, practice or method is appropriate for the pollutant and the fuel matrix; or is cited as an appropriate sample preparation standard, practice or method for the pollutant in the chosen VCS or EPA determin ative 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 publ ished VCS or EPA method to obtain moisture content. If the sample analysis plan calls for determining mercury using an aliquot of the dried sample, then the drying temperature must be modified to prevent vaporizing th i s metal. On the other hand, if metal s analysis is done on an "as received" basis, a separate aliquot can be dried to determine**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **235** of **255** moisture content and the me rcury concentration mathematically adjusted to a dry basis. (6) An equivalent mercury determinative or analytical procedure means a publ ished VCS or EPA method that clearly states that the standard, practice, or method is appropriate for
mercury and the fuel matrix and has a published detection limit equal or lower than the methods listed in Table 5 to this subpart for the same purpose.
F abric filter means an add

- on air pollution control device used to capture particulate matter by filtering gas streams through filter media, also known as a baghouse. Federally enforceable means all limitations and conditions that are enforceable by the EP A Administrator, including the requirements of 40 CFR part 60 and 40 CFR part 61, 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. Fuel type me ans 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, distillate oil, residual oil. Gaseous fuels includes, but is not limited t o, natural gas,**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **236** of **255** process gas, landfill gas, coal derived gas, refinery gas, hydrogen, and biogas.
Gas

- fired boiler includes any boiler that burns gaseous fuels not combined with any solid fuels, burns liquid fuel only during periods of gas curtailment, gas supply emergencies, or periodic testing on liquid fuel. Periodic testing of liquid fuel shall not exceed a combined total of 48 hours during any calendar year. Heat input means heat derived from combustion of fuel in a boiler and does not include the he at input from preheated combustion air, recirculated flue gases, or returned condensate. Hot water heater means a closed vessel with a capacity of no more than 120 U.S. gallons in which water is heated by combustion of gaseous or liquid fuel and is withdra wn for use external to the vessel at pressures not exceeding 160 psig, including the apparatus by which the heat is generated and all controls and devices necessary to prevent water temperatures from exceeding 210 degrees Fahrenheit (99 degrees Celsius )
. Industrial boiler means a boiler used in manufacturing, processing, mining, and refining or any other industry to provide steam, hot water, and/or electricity. Institutional boiler means a boiler used in institutional**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **237** of **255** establishments such as medical center s, research centers, and institutions of higher education to provide electricity, steam, and/or hot water . Liquid fuel means, but not limited to, petroleum, distillate oil, residual oil, any form of liquid fuel derived from petroleum, used oil, liquid bio fuels, and biodiesel. Minimum scrubber pressure drop means 90 percent of the average scrubber pressure drop measured according to Table 3 to this subpart during the most recent performance stack test demonstrating compliance with the applicable emission li mit. Minimum sorbent flow rate means the boiler load (percent) multiplied by 90 percent of the test average sorbent (or activated carbon ) injection rate measured according to Table 3 to this subpart during the most recent performance stack test demonstra ting 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 3 to this subpart during the most recent performance st ack test demonstrating compliance with the applicable emission limits. Natural gas means: (1) A naturally occurring mixture of hydrocarbon and**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **238** of **255** nonhydrocarbon gases found in geologic formations beneath the earth’s surface, of which the principal constit uent is methane , including intermediate gas streams generated during processing of natural gas at production sites or at gas processing plants ;

or (2) Liquefied petroleum gas, as defined by the American Society for Testing and Materi als in ASTM D1835

- 0 5 (incorporated by reference, see §63.14(b) ; or ( 3) A mixture of hydrocarbons that maintains a gaseous state at ISO conditions. Additionally, natural gas must either be composed of at least 70 percent methane by volume or have a gross calorific value betw een 34 and 43 megajoules (MJ) per dry standard cubic meter (910 and 1,150 Btu per dry standard cubic foot) ; or (4) Propane or propane derived synthetic natural gas. Propane means a colorless gas derived from petroleum and natural gas, with the molecular structure C 3 H 8 . Oil subcategory includes any boiler that burns any liquid fuel and is not in either the biomass or coal subcategories.
Gas

- fired boilers that burn liquid fuel during periods of gas curtailment, gas supply emergencies, or for periodic test ing , not to exceed 48 hours during any calendar year, of liquid fuel**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **239** of **255** are not included in this definition. Opacity means the degree to which emissions reduce the transmission of light and obscure the view of an object in the background. Particulate matter (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. Performance testing means the collection of data resulting from the execution of a test method used (either by stack testing or fuel analysis) to demonstrate compliance with a relevant emission standard. Period of natural gas curtailment or supply interruption means a period of time during which the supply of natural gas to an affect ed facility is halted for reasons beyond the control of the facility. The act of entering into a contractual agreement with a supplier of natural gas established for curtailment purposes does not constitute a reason that is under the control of a facility for the purposes of this definition. An increase in the cost or unit price of natural gas does not constitute a period of natural gas curtailment or supply interruption. Qualified Energy Assessor mean a specialist in evaluating**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **240** of **255** energy systems, such as, a person who have successfully completed the DOE Qualified Specialist program for all systems, Certified Energy Managers certified by the Association of Energy Engineers, or a person who has demonstrated capabilities to perform and evaluate a full assessme nt of energy savings opportunities available for boiler and energy use systems and technical expertise and tools to estimate cost and energy savings. Steam and energy use systems include, but not limited to : a. Boiler combustion management b. Boiler thermal ener gy recovery 1. Conventional feedwater economizer 2. C onventional combustion air preheater 3. Condensing economizer

c. Boiler blowdown thermal energy recovery d. Primary energy resource selection 1. Fuel (primary energy source) switching, 2. Applied steam energy versus direct f ired energy versus electricity
e. Insulation issues f. Steam trap and steam leak management g. Condensate recovery h. Steam end

- use management Capabilities and knowledge includes, but is not limited to:

a . B ackground, experience, and recognized abilities to perform th e assessment activities, data analysis, and report preparation**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **241** of **255** b

. F amiliarity with operating and maintenance practices for steam or process heating systems 1. additional potential steam system improvement opportunities including improving steam turbine operat ions and reducing steam demand 2. additional process heating system opportunities including effective utilization of waste heat and use of proper process heating methods 3. boiler

- steam turbine cogeneration systems, 4. industry specific steam end

- use systems Quali fied personnel

Responsible official means responsible official as defined in 40 CFR 70.2. mean specialists in evaluating energy systems, such as, those who have successfully completed the U.S. Department of Energy Qualified Specialist program for all systems, Certified Energy Manager certified by the Association of Energy Enginee rs, or the equivalent.

Solid fossil fuel includes, but not limited to, coal, petroleum coke, and tire derived fuel (TDF).
Tune

- up means adjustments made to a boiler in accordance with procedures supplied by the manufacturer (or an approved specialist) to optimize the combustion efficiency. Waste heat boiler means a device that recovers normally unused energy and converts it to usable heat. Waste heat boilers are also referred t o as heat recovery steam generators.**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **242** of **255** Work practice standard means any design, equipment, work practice, or operational standard, or combination thereof, which is promulgated pursuant to section 112(h) of the CAA.

**Table 1 to Subpart JJJJJJ of Part 63**  **— Emission Limits**  As stated in §63.11201, you must comply with the following applicable emission limits:

**If your boiler is in this**  **subcategory... For the**  **following pollutants...**  **You must achieve less**  **than or equal to the**  **following emission limits**  **, exc ept during**  **periods of startup and shutdown**  **...** 1. New coal

- fired boiler with heat input capacity of 30 million Btu per hour or greater a. Particulate Matter b. Mercury

c. Carbon Monoxide 0.03 lb per MMBtu of heat input. 0.0000048 lb per MMBtu of heat input. 400 ppm by volume on a dry basis corrected to 3 percent oxygen. 2. New coal

- fired boiler with heat input capacity of between 10 and 30 million Btu per hour a. Particulate Matter b. Mercury

c. Carbon Monoxide 0.42 lb per MMBtu of heat input. 0.0000048 lb per MMBtu of heat input. 400 ppm by volume on a dry basis corrected to 3 percent oxygen. 3. New biomass

fired boiler with heat input capacity of a. Particulate Matter 0.03 lb per MMBtu of heat input.**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **243** of **255** 30 millionBtu per hour or greater

4. New biomass fired boiler with heat input capacity of between 10 and 30 million Btu per hour a. Particulate Matter 0.07 lb per MMBtu of heat input.

5. New oil

- fired boiler with heat input capacity of 10 million Btu per hour or greater a. P articulate Matter 0.03 lb per MMBtu of heat input.

6. Existing coal ( units with heat input capacity of 10 million Btu per hour or greater) a. Mercury

b. Carbon Monoxide 0.0000048 lb per MMBtu of heat input. 400 ppm by volume on a dry basis corr ected to 3 percent oxygen.

**Table 2 to Subpart JJJJJJ of Part 63 —**  **Work Practice Standards, Emission Reduction Measures, and Management Practices**  As stated in §63.1120 1 , you must comply with the following applicable work practice standards , emission re duction measures, and management practices : **If your boiler is in You must meet the following...** **Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **244** of **255 this subcategory...**  1. Existing or new coal ( units with heat input capacity of 10 million Btu per hour or greater ) Minimize the boiler’s time spent during s tartup and shutdown following the manufacturer’s recommended procedures.
2 . Existing or new coal ( units with heat input capacity of less than 10 million Btu per hour) C onduct a tune

- up of the boiler bie nn i ally as specified in §63.11222.

3 . Existing or new biomass or oil C onduct a tune

- up of the boiler bie nn i ally as specified in §63.11222.
4 . Existing coal, biomass, or oil ( units with heat input capacity of 10 million Btu per hour and greater ) Must have a one - time energy a ssessmen t performed by qu alified personnel which includes:

(1) a visual inspection of the boiler system. (2) establish operating characteristics of the facility, energy system specifications, operating and maintenance procedures, and unusual operating constraints, (3) identify major systems consuming energy from affected boiler(s) , (4) a review of available architectural and engineering plans, facility operation and maintenance procedures and logs, and fuel usage, (5) a list of major energy conservation measures, (6) the ene rgy savings potential of the energy conservation measures identified, (7) a comprehensive report detailing the ways to improve efficiency, the cost of specific improvements, benefits, and the time frame for recouping those investments,**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **245** of **255**

**Table 3 to Subp art JJJJJJ of Part 63**  **— Operating Limits for**  **Boilers with Emission Limits** As stated in §63.11201, you must comply with the applicable operating limits:

**If you demonstrate compliance with**  **applicable emission limits using...**  **You must meet these operating l**  **imits...** 1. Fabric filter control a. Maintain opacity to less than or equal to 10 percent opacity (daily block average); OR b. Install and operate a bag leak detection system according to §63.1122 4 and operate the fabric filter such that the bag leak det ection system alarm does not sound more than 5 percent of the operating time during each 6

- month period. 2. Electrostatic precipitator control a. Maintain opacity to less than or equal to 10 percent opacity (daily block average) ; OR b. Maintain the minim um voltage and secondary amperage ( or total power input ) of the electrostatic precipitator at or above the operating limits established during the performance test. 3. Wet scrubber control Maintain the minimum pressure drop and liquid flow

- rate at or abo ve the operating levels established during the performance test. 4. Dry sorbent or carbon injection control Maintain the minimum sorbent or carbon injection rate at or above the operating levels established during the performance test

.**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **246** of **255** 5. Any other add

- o n air pollution control type. This option is for boilers that operate dry control systems. B oilers must maintain opacity to less than or equal to 10 percent opacity (daily block average). 6. Fuel analysis Maintain the fuel type or fuel mixture (annual av erage) such that the mercury emission rates calculated according to §63.11211( b ) is less than the applicable emission limits for mercury.

**Table 4 to Subpart JJJJJJ of Part 63 —**  **Performance (Stack) Testing Requirements**  As stated in §63.11212 , you must comply with the following requirements for performance (stack) test for affected sources:

**To conduct a performance**  **test for the following**  **pollutant... You must...**  **Using...** 1. Particulate Matter a. Select sampling ports location and the number of traverse points. b. Determine velocity and volumetric flow

rate of the stack gas.

c. Determine oxygen and carbon dioxide concentrations of the stack gas. Method 1 in appendix A to part 60 of this chapter.

Method 2, 2F, or 2G in appendix A to part 60 of this chapter. Method 3A or 3B in appendix A to part 60 of this chapter , or ASTM D6522

- 00 (IBR, see §63.14(b)), or ASME**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **247** of **255**

d. Measure the moisture content of the stack gas

e. Measure the particulate matter emissio n concentration.

f. Convert emissions concentration to lb/ MMBtu emission rates. PTC 19, Part 10(1981)(IBR, see §63.14(i)). Method 4 in appendix A to part 60 of this chapter. Method 5 or 17 (positive pressure fabric filters must use Method 5D) in appendix A to part 60 of this chapter. Method 19 F

- factor methodology in appendix A to part 60 of this chapter.**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **248** of **255**
2. Mercury a. Select sampling ports location and the number of traverse points. b. Determine velocity and volumetric flow

rate of the stack gas.

c. Determine oxygen and carbon dio xide concentrations of the stack gas.

d. Measure the moisture content of the stack gas.

e. Measure the mercury emission concentration.

f. Convert emissions concentration to lb/ MMBtu emission rates. Method 1 in appendix A to part 60 of this c hapter.

Method 2, 2F, or 2G in appendix A to part 60 of this chapter. Method 3A or 3B in appendix A to part 60 of this chapter, or ASTM D6522

- 00 (IBR, see §63.14(b)), or ASME PTC 19, Part 10(1981)(IBR, see §63.14(i)). Method 4 in appendix A to part 60 of this chapter. Method 29 in appendix A to part 60 of this chapter or Method 101A in appendix B to part 61 of this chapter or ASTM Method D6784

- 02 (IBR, see §63.14(b)). Method 19 F

- factor methodology in appendix A to part 60 of this chapter.**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **249** of **255**
3. Carb on Monoxide a. Select the sampling ports location and the number of traverse points. b. Determine oxygen and carbon dioxide concentrations of the stack gas.

c . Measure the moisture content of the stack gas. d

. Measure the carbon monoxide emission concentration. Method 1 in appendix A to part 60 of this chapter.

Method 3A or 3B in appendix A to part 60 of this chapter, or ASTM D6522

- 00 (IBR, see §63.14(b)), or ASME PTC 19, Part 10(1981)(IBR, see §63.14(i)). Method 4 in appendix A to part 60 o f this chapter. Method 10, 10A, or 10 B in appendix A to part 60 of this chapter or ASTM D6522

- 00 (IBR, see §63.14(b). **Table 5 to Subpart JJJJJJ of Part 63 —**  **Fuel Analysis Requirements**  As stated in §63.11213, you must comply with the following requir ements for fuel analysis testing for affected sources:

**To conduct a fuel analysis**  **for the following**  **pollutant... You must...**  **Using...** 1. Mercury a. Collect fuel samples. Procedure in §63.11213(c) or ASTM D2234

- D2234M

- 03 € 1 (for coal)(IBR, see §63.14(b)) or ASTM**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **250** of **255**

b. Compose fuel samples.

c. Prepare composited fuel samples.

d. De termine heat content of the fuel type.

e. Determine moisture content of the fuel type.

f. Measure mercury concentration in fuel sample. D6323

- 98 (2003)(for biomass)(IBR, see §63.14(b)) or equivalent. Procedure in §63.11213(c) or equivalent.
SW

- 846

- 3050B (for solid samples) or SW

- 846

- 3020A (for liquid samples) or ASTM D2013

- 04 (for coal) (IBR, see §63.14(b)) or ASTM D5198

- 92 (2003) (for biomass)(IBR, see §63.14(b)) or equivalent. ASTM D5865

- 10a (for coal)(IBR, see §63.14(b)) a or ASTM E711

- 87 (1996) (for biomass)(IBR, see §63.14(b)) or equivalent.

ASTM D3173

- 03 (IBR, see §63.14(b)) b or A STM E871

- 82 (1998)(IBR, see §63.14(b)) or equivalent.

ASTM D6722

- 01 (for coal)(IBR, see §63.14(b)) c or SW

- 846

- 7471A (for solid samples) or SW

- 846 7470A (for liquid samples) or equivalent.**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **251** of **255**

g. Convert concentrations into units of lb/MMBtu of heat content.
a ASTM D5865

– 10a , “ Standard Test Method for Gross Calorific Value of Coal and Coke ” b ASTM D3173

– 03 (2008) , “ Standard Test Method for Moisture in the Analysis Sample of Coal and Coke ” c ASTM D6722

– 01 (2006) , “ Standard Test Method for Total Mercury in Coal and Coal Combustion Residues by the Direct Combustion Analysis ”
**Table 6 to Subpart JJJJJJ of Part 63 —**  **Applicability of General Provisions to Subpart JJJJJJ**  As stated in §63.11235, you must comply with the applicable General Provisions according to the following:

**General Provisions**  **Cit e**  **Subject Does it a**  **ppl y?** 

§63 .1 Applicability Yes. §63.2 Definitions Yes. Additional terms defined in §63.11237

. §63.3 Units and Abbreviations Yes.

§63.4 Prohibited Activities and Circumvention Yes.

§63.5 Preconstruction Review and Notification Requirements No

§63.6(a), (b)(1)

- ( b)(5), (b)(7), (c), (f)(2)

- (3), (g), (i), (j) Compliance with Standards and Maintenance Requirements Yes.**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **252** of **255**
§63.6(e)(1) (i) General Duty to minimize emissions No. S ee § 63. 11205 for general duty requirement

. §63.6(e)(1) (ii) Requirement to correct malfuncti ons ASAP No.

§63.6(e)(3) SSM Plan No. §63.6(f)(1) SSM exemption No. §63.6(h)(1) S SM exemption No. §63.6(h)(2) to (9) Determining compliance with opacity emission standards Yes.

§63.7(a),(b),(c), (d),(e)(2)

- (e)(9), (f),(g), and (h) Performance Testing R equirements Yes.

§63.7(e)(1) P erformance test ing No. S ee §63.11210.

§63.8 (a),(b),(c)( 1),(c)(1)(ii),(c) (2) to (c)(9),(d)(1)and( d)(2), (e),(f), and (g) Monitoring Requirements Yes.

§63.8(c)(1)(i) General duty to minimize emissions and CMS operation No .

§63.8(c)(1)(iii) Requirement to develop SSM P lan for CMS No.

§63.8 (d)(3) Written procedures for CMS Yes, except for the last sentence, which refers to a n SSM plan. S SM plans are n o t required

. §63.9 Notification Requirements Yes.**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **253** of **255**
§63.10(a) and (b)(1) Recordkeeping and Reporting Requirements Yes.

§63.10(b)(2)(i) Recordkeeping of occurrence and duration of startups or shutdowns No.

§63.10(b)(2)(ii) Recordkeeping of malfunctions No. See §63.11225 for recordkeeping of (1) occurrence and duration and (2) actions taken during malfunctions. §63.10(b)(2)(iii) Maintenance records Yes.
§63.10(b)(2)(iv) and (v) Actions taken to minimize emissions during SSM No.

§63.10(b)(2)(vi) Recordkeeping for CMS malfunctions Yes.
§63.10(b)(2)(vii) to (xiv) Other CMS requirements Yes.
§63.10(b)(3) Recordkeeping requirements for applicability determinations No.

§63.10(c)(1) to (9) Recordkeeping for sources with CMS Yes.
§63.10(c)(10) Recording nature and cause of malfunctions No. See §63.11225 for malfunction re cordkeeping requirements. §63.10(c)(11) Recording corrective actions No. See §63.11225 for malfunction recordkeeping requirements. §63.10(c)(12) and (13) Recordkeeping for sources with CMS Yes.**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **254** of **255**
§63.10(c)(15) Allows u se of SSM p lan No.
§63.10(d)(1) and (2) General reporting requirements Yes.
§63.10(d)(3) Reporting opacity or visible emission observation results No.

§63.10(d)(4) Progress reports under an extension of compliance Yes.

§63.10(d)(5) S SM reports No. See §63. 11225 for malfunction reporting requirements. §63.10(e) and (f) Yes. §63.11 Control Device Requirements No.

§63.12 State Authority and Delegation Yes.

§63.13

- 63.16 Addresses, Incorporation by Reference, Availability of Information, Performance Track Provis ions Yes.**Draft 12/10/2010 --**  **This draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***

Page **255** of **255**
§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). Reserved No.