*****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** *** 6560

- 50

- 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 Boilers** 
**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 institutional 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 pollutants 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

m anagement practices

. **EFFECTIVE DATE :**  Th is final rule is effective on [ INSERT THE
DATE 60 DAYS AFTER THE DATE OF PUBLICATION OF THIS FINAL RULE IN
THE FEDERAL REGISTER ]. The incorporation by reference of certain publications listed in th is final rule were approved 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draft has not been formatted or copyedited for Federal Register style.**  *****E.O. 12866 Review –**  **Draft –**  **Do Not Cite, Quote or Release During Review** ***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 **2** of **298** the director of the Federal Register as of [ INSERT THE DATE 60
DAYS AFTER THE DATE OF PUBLICATION OF THIS FINAL RULE IN THE
FEDERAL 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. Certa in other material, such as copyrighted material, is not placed on the Internet and will be publicly available only in hard copy form. Publicly available docket materials are available either electronically through http://www.regulations.gov or in hard cop y 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 t he 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.**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 **298** Environmental Protection Agency , Research Triangle Park, N orth Carolina 27711 ; T elephone number : (919) 541

- 5 426 ; F ax number (919) 541

- 5450 ; 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 Continuous Emission Monitoring System
CFR Code of Federal Regulations
CO Carbon monox ide

ERT Electronic Reporting Tool

FR Federal Register
GACT Generally Available Control Technology

HAP Hazardous Air Pollutant HCl Hydrogen chloride
ICR Information Collection Request kWh k ilowatt hour
MACT Maximum Achievable Control Technology MMBtu/h Million Btu per hour
NAICS North American Industry Classification System**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 **298** NESHAP National Emission Standards for Hazardous Air Pollutants
NOx Nitrogen oxides
NSPS New Source Performance Standards
PM p articulate matter

PM 2.5 f ine particulate matter
POM Poly cyclic 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 Prediction 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 national emission standards? D. How did we gather i nformation for this rule? E. How are the area source boiler HAP addressed by this rule?**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 **298**
**III . Summary of**  **this final rule** A. Do these standards apply to my source? B. What is the affected source? C. When 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 requirements? H. What are the notification, recordkeeping an d 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/E mission 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. Compliance Requirements I. C ost/Economic I mpacts **VI.** Summary of the Impacts **Relationship of this**  F inal R ule **Action to CAA Section 112(c)(6)**  **V I**  **I .**  **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 impacts? 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 Formatted: Font: 12 pt, Bold Formatted: Normal Formatted: Font: 12 pt, Bold**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 **298** B. Paperwork Reduction Act C. Regulatory Flexibility Act (RFA) D. Unfunded Mandates Reform Act of 1995 E. Executive Order 13132: Federalism F. Executive Order 13175: Consultation and Coordination with Indian Tribal Go vernments 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 T ransfer and Advancement Act J. Executive Order 12898: Federal Actions to Address Environmental Justice in Minority Populations and Low

- Income Populations K. Congressional Review Act **I. General Information**
A. The regulated c ategories and entities potentially affected by the final standards include: Does this action apply to me?**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 **298**
Category 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 manufacturing

. 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. 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 whether 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, and Institution al Boilers Area Sources )
. If you have any que stions**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 **298** 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 Network ( TTN ). Following signature, a copy of the final actio n will be posted on the TTN’s policy and guidance page for newly proposed or promulgated rules at the following address: http://www.epa.gov/ttn/oarpg . The TTN provides information and technology exchange in various areas of air pollution control. Wh ere can I get a copy of this document ?

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 Circuit (the Court) by [ Judicial Review

INSERT THE DATE 60 DAYS FROM AFTER THE DATE OF
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**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 **298** 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 the preceding **FOR FURTHER GENERAL INFOR MATION 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 statutory authority and regulatory approach 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 **10** of **298** 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 potential to emit 10 tp y 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, 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**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 **298** 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 hazardous 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 tec hniques which are commercially available and appropriate 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 le gislative history, we can consider costs and economic impacts in determining GACT, which is particularly important when developing regulations for source categories that may have many sm all businesses such as these

. Determining what constitutes GACT involv es 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 categor y to determine if the contr ol technologies and management practices are transferable and generally available to area sources. In appropriate circumstances, we may also consider technologies and practices at area and major sources in similar categories to determine**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 **298** whether such tech nologies and practices could be considered generally 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 category. 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 acc ounting for not less than 90 percent of the aggregate 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 HAP specified in CAA sectio n 112(c)(6) are as follows: alkylated lead compounds, 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**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 **298** combustion. ( See 63 FR 17849 ( , April 10, 1998 )
. )
. ) We listed these source categories under CAA section 112(c)(6) based on the source categories’ contribution of mercury and POM

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

. (See “1990 Emissions Inventory of Section 112(c)(6) Polluta nts, Final Report,” 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 comments received, we re - exa mine d the emission inventory and the need to address POM emissions from the area 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 catego ries under CAA section 112( d )( 2 ) or 112(d)(4)

. With this final rule and the major 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**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 **298** for mercury and POM

. Consequently, we are regulat ing coal

- fired

area source boilers under MACT because 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 ba sed on the emissions reductions achievable through application of measures, processes, methods, systems, or techniques including, but not limited to: (1) reducing the volume of, or eliminating emissions of, such pollutants through process changes, substit utions of materials, or other modifications; (2) enclosing systems or processes to eliminate emissions; (3) collecting, capturing, or treating such pollutants when released from a process, stack, storage or fugitive emission point; (4) design, equipment, w ork 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 achieved 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**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 **298** standards for new sources, but they cannot be less stringent than the average emission limitation 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 for 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 n umerical 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 economic limitat ions. S ection 112(h) of the CAA authorizes the Administrator to promulgate a design, equipment, work practice, or operational standard, or combination thereof, consistent with the provisions of CAA sections 112(d) or (f), in those cases where, in the judg ment 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 Administrato r determines that ... the application 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 **16** of **298** 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, indu strial oil combustion, industrial wood combustion, commercial coal combustion, commercial oil combustion, and commercial wood combustion under CAA section 112(c)(6) based on the source categories’ contribution of mercury and POM

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

- PAH (polynuclear aromatic hydrocarbons)), ethylene dioxide, and PCB s . We have developed final standards to reflect the 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 sour ce 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**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 **298** 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 industrial boilers, institutional boilers, and commercial boilers located
at area sources. Boiler means an enclosed combustion device having the primary purpose of recovering thermal energy in th e form of steam or hot water. The industrial boiler source category includes boilers used in manufacturing, processing, mining, refining, or any other industry. The commercial boiler source category includes boilers used in commercial establishments such as stores/malls, laundries, apartments, restaurants, and hotels/motels. The i nstitutional boiler source category includes boilers used in medical centers (e.g., hospitals, clinics, nursing homes), ed ucational 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 th e form of steam or hot
water. Formatted: Style 12 pt Line spacing: Double, Indent: First line: 0", Line spacing: single**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 **298** 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 pursuant to CAA section 129 for commercial and industrial solid waste inci neration units. In a parallel action, EPA is finaliz ing a solid waste definition rulemaking pursuant 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 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 **19** of **298** 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, September 22, 2005), which amended the definitions of “commercial and industrial solid waste incinerator (CISWI),” “commercial or industrial waste,” and “solid w aste” 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 standards any facility that combusts any commercial or industrial solid waste material at all

— subject to the four statutory exceptions 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**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 **298** definition of "solid waste" pursuant to the rulemaking of

s ubtitle D of RCRA. A boiler located at an area source burning any secondary materials cons idered " 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 a nd 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 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 PM, 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 monitoring 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 **21** of **298** 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’ states’ boiler inspection lists , company w ebsites, published literature,
State state permits, current State s tate and Federal f ederal regulations , and from an ICR conducted for the major source
NESHAP
. After proposal, we received additional emission test reports during the public comment period

. We developed an initial nationwide population of area

source boiler s based on boiler inspector data

- base s from 13
S tates states . 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 boiler was located

. However, many of the boilers in the boiler inspector data

- base could not be readily assigned to an NAICS code and, thus, we did not categorize them

. We reviewed S tate s tate and other F ederal f ederal regulations that apply to the area sources in the source categories for information concerning existing HAP emission control approaches.
For example, as noted above, the NSPS for small industrial,**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 **298** commercial, and institutional boilers in 40 CFR part 60, subpart
Dc apply to boilers at some area sources. Similarly, permit requirements established 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. F or example, we determined that management practices , such as, annual tune

- ups and operator training applicable to major source boilers are equally also 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 C AA section 112(c)(6) due to contributions of mercury and POM and these same categories are listed under CAA section 112(c)(3) for 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**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 **298** 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 PC B ) . 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 - mer cury 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 s pecies is difficult given the level of uncertainty about the individual non

- mercury metal HAP 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 co ntained 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**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 **298** surrogate for these HAP and for their control. 1

For organic urban HAP, we selected CO as a surrogate for organic compounds , including 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

. because organic HAP, like CO, are formed as a byproduct of combustion , and both would increase with an increase in the level of incomplete combustion

. Monitoring equipment for CO is readily available, which is not the case for organic HAP. Also, it is significantly eas ier and less expensive to measure and monitor Therefore, the same control techniques that would be used to contro l 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 significantly more complex compliance and monitoring requirements and achieve little, if any, HAP emissions reductions beyond what would be achieved using the surrogate pollutant approach.

1 In National Lime Ass’n v. EPA , 233 F. 3d 625, 633 (DC Cir. 2 000) , the court upheld EPA’s use of particulate matter as a surrogate for HAP metals

.**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 **298** CO emissions than to measure and monitor emissions of each individual organic HAP. We considered other surrogates, such as total hydrocarbon ( THC ), but lacked data on emissions and permit limits for area sourc e 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 emissions. 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 biomass

- 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**  **R ule** 
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 standards 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 **26** of **298** 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 which switches 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 OF THIS FINAL RULE
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 OF
THIS FINAL RULE IN THE FEDERAL REGISTER ]. The owner or operator of a new source is required to co mply on [ INSERT THE DATE 60**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 **298** DAYS AFTER THE DATE OF PUBLICATION OF THIS FINAL RULE 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 combusti ng 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 ur ban 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. Merged Cells Formatted Table Merged Cells**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 **298**
b. Mercury 0.0000048 lb per MMBtu of heat input.

c. Carbon Monoxide 400 ppm by volume on a dry basis corrected to 3 percent oxygen. ≥ 10 and < 30 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
. b. Mercury 0.0000048 lb per MMBtu of heat input.

c. Carbon Monoxide 4 00 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 of 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. Formatted Table**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 **298** Existing coal

- Fired boiler ≥ 10 a. Mercury

b. Carbon Monoxide 0.0000048 lb per MMBtu of heat input. 400 ppm by volume on a dry basis corrected to 7 percent oxygen. b. Carbon Monoxide 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 existing 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 15 percent biomass on a total 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 either the coal or the biomass subcategory, the un it 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

- fired

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 Merged Cells Formatted Table Merged Cells**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 **298** 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 sour ce 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 greater that require s the
pe rformance of an energy a ssessment , by qualified personnel, on the boiler and its energy us e systems to identify cost

- effective energy conservation measures.
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 Provisio ns Rule” (40 CFR 63, subpart A), that EPA promulgated under CAA section 112 of the CAA. 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 **31** of **298** 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 otherwise 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 into account startup and shut down periods and, for the reasons explained below , has established different standards for those periods. EPA has revised this final rule to require sources to perform only meet a work practice standards standard , including following the manufacturer’s rec ommended procedures for minimizing startup and shutdown periods , to demonstrate compliance with the CO emission limits for all subcategories of new and existing area source coal

- fired boilers (that would otherwise be subject to numeric emission limits) during periods of startup and shutdown. As discussed in Section VI.G of this preamble, we considered whether continuous emission monitoring**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 **298**

or performance testing , and therefore, enforcement of numeric emission limits, would be feasible for area source bo ilers practica ble during periods of startup , and 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 f easible to require complete 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 practice standard s standard for periods of startup and shutdown

. Periods of startup, normal operations, and shutdown are all predictable and routine aspects of a source’s operations. However, by contrast, malfunction is defined as a “sudden, infrequent, and not reasonably preventable failure of air pollution control and monitoring equipment, process equipment or a process to operate in a normal or usual manner . . .” (40 CFR 63.2). EPA has determined that malfunctions should not be viewed as a distinct operating mode and, therefore, any emissions that occur at such times do not need to be factored into development of CAA section 112(d) standards, which, once**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 **298** promulgated, apply at all times. In Mossville Environmental Action Now v. E PA , 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 anticip ate all upset situations. After a certain point, the transgression of regulatory limits caused by ‘uncontrollable acts of third parties,’ such as strikes, sabotage, operator intoxication or insanity, and a variety of other eventualities, must be a matter f or the administrative exercise of case

- by

- case enforcement discretion, not for specification in advance by regulation.”)

. Further, it is reasonable to interpret CAA section 112(d) as not requiring EPA to account for malfunctions in setting emissions standards. For example, we note that CAA s ection 112 uses the concept of “best performing” sources in defining MACT, the level of stringency that major source standards m ust meet. Applying the concept of “best performing” to a source that 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 **34** of **298** 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 standa rds for

area sources are generally not required to be set based on “best performers,” we believe that what is "generally available" 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) standards for area source boilers . As noted above, by definition, malfunctions are sudden and unexpected events and it would be d ifficult to set a standard that takes into account the myriad different types of malfunctions that can occur across all sources in the category. Moreover, malfunctions can vary in frequency, degree, and duration, further complicating standard setting.

In the event that a source fails to comply with the applicable CAA section 112(d) standards as a result of a malfunction event (see 40 CFR 63.2 (definition of malfunction),

EPA must determine an appropriate response based on, among other things, the good fai th efforts of the source to minimize**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 **298** emissions during malfunction periods, including preventative and corrective actions, as well as root cause analyses to ascertain and rectify excess emissions. EPA would also consider whether the source's failure to com ply with the CAA section 112(d) standard was, in fact, “sudden, infrequent, not reasonably preventable” and was not instead “caused in part by poor maintenance or careless operation.” ( See 40 CFR 63.2 (definition of malfunction). ) Finally, EPA recognize s 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 Duri ng Malfunctions, Startup, and Shutdown (Sept ember 20, 1999); Policy on Excess 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 de fendant, regarding which the defendant has the burden of proof, and the merits of which are independently**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 **298** and objectively evaluated in a judicial or administrative proceeding).) We also have added other regulatory provisions to specify the elements that a re 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 succe ssfully 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 of air pollution control and monitoring equipment, process equipme nt, or a process to operate in a normal or usual manner....” The criteria also are designed to ensure that steps are taken to correct the malfunction, to minimize emissions in accordance with 40 CFR 63. 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**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 **37** of **298** limitations were being exceeded...” and that “[a]ll possible steps were taken to minimize the impact of the excess emissions on ambient air quality, the environment and human health....” In any judicial or administrative proceeding, the Administrator may challenge the assertion of the affirmative defense and, if the respondent has not met its burden of provin g 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 emission limits. The performance tests to demonstrate compliance with 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 specified 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 establ ishes your site

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

- fired 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 **38** of **298**

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 s ubmit 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, documentation that the energy assessment was performed and the cost

- effective energy conservation measures identified.
G
. What are the continuous compliance requiremen ts ? If you demonstrate initial compliance with the emission limits by performance (stack) tests, then you must conduct stack tests on an annual basis. Furthermore, t o demonstrate continuous compliance with the PM , CO, and mercury emission limits, you mus t monitor and comply with the applicable site

specific operating limits.
For area source boilers 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

a verage) 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 **39** of **298** 1. If the boiler is controlled with a fabric filter, the fabric filter may be continuously 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 boi ler is controlled with an electrostatic precipitator (ESP), you must maintain the minimum voltage 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 co ntrolled with a wet scrubber, you must monitor pressure drop and liquid flow rate of the scrubber and maintain the daily block averages at or above the minimum operating limits established during the performance
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 y ou elected to demonstrate initial compliance with the mercury emission limit by fuel analysis , as determined accor ding**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 **298** 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) a s set during the performance test. If you plan to burn a new fuel type or new mixture that is different from what was burned during 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

. For boilers that must comply with the CO emission limits, you must continually monitor oxygen and maintain an oxygen concentration level, on a 30

- day rolling average basis, at no less than 90 percent of the avera ge oxygen concentration measured during the most recent performance test. Biomass and oil

- fired boilers must meet the management practice standards defined in Table 2 to 40 CFR part 63 , subpart
JJJJJJ
. H
. What are the notification, recordkeeping and reporting requirements ?**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 **298** 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 are 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 rovisio ns 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 previous 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

. Th is rule require s records to demonstrate compliance with each emission limi t, work practice standard, and management**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 **298** practice. These recordkeeping requirements are specified directly in the General Provisions to 40 CFR part 63

. Records for applicable management practices must be maintained. Specifically, 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 opacity 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 fuel type burned, and units of m easure; (5) A copy of the results of all performance tests, 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 **43** of **298**

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 updated 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 stack test reports in electroni c format as a replacement for bulky paper copies. In this action, we are taking a step to improve data accessibility for stack tests (and in the future continuous monitoring data). Boiler area sources are required to submit 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 **44** of **298** 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 contracted 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 requirements for data com pilation; 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 required in the existi ng 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 already 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 standardized method to compile and store all the documentation required by s ubpart JJJJJJ

. Another important benefit 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 **45** of **298** 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 affected faciliti es (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 procedures. 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 accurat e. In summary, receiving these test data already collected for other purposes and using them in the emissions factors development program will

save industry, State s tate /local/tribal agencies, and EPA time and money.**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 **298** As mentioned earlier, the electronic d ata

- 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.html

. 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. Chang es to Subcategories We have redefined the coal, biomass and oil sub categories for area source bo ilers to clarify the fuel

- type inputs 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 **47** of **298** would define each s ub category. The proposed rule defined the biomass subcategory to include any boiler that burns 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 coa l

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 burns 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 e ither 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 ).
B
. Change from MACT to GACT for Biomass and Oil Subcategories**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 **298** 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 For 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 a nd oil subcategories. 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 h ave determined that 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 no rmal and log

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

normal results. We have also revised the UPL calculation 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 **49** of **298** convert log

- normally distributed data to an arithmetic mean inste ad 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 source 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 im mediate and long

- term 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 productiv ity 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 systems, list ing maj or energy conservation measures, and a comprehensive report detailing the ways to improve efficiency, the cost of specific improvements, and the benefits associated with such.**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 **298** This final rule requires an energy asses sment for all existing 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 pe rforming the energy 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 affected 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 id entify energy savings 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 f acilities with affected boilers using greater than 1 TBtu /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 **51** of **298** heat input , the energy assessment must comprise 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 boiler system , which must be considered during the energy assessment.

E
. Revised Subcategory Limits The MACT emission limits for the coal subcategory have been revised based on the revised MACT floor approach (see Section V of this preamble). The revised limits 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 ne w area source boilers and for existing area source boilers with a heat input capacity of 10 MMBtu/h or greater . The proposed rule also set emission limits for mercury from new and existing coal

- fired 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 **52** of **298** In this final rule, the emission limits for mercury and CO have been revised for existing coal

- fired boilers with a heat input capacity greater than 10 MMBtu/h. The MACT emission limits for the coal subcategory have been revised based on the revised MACT floor approach (see Section V of this preamble). Existing boilers in the biomass and oil subcategories are not required to meet emission limits for CO in this final rule; these units must meet the management practice standards of implementing a boiler tun e - up program.
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 manag ement 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 N ew boilers in the biomass and oil subcategories are not required to 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

. 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 **53** of **298**
tune

- up . 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

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 corrected to 7 percent oxygen . 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
.

Mercury 0.000003 lb per MMBtu of heat input. 0.0000048 lb per MMBtu of heat input.

Carbon Monoxide 310 ppm by volume on a dry basis corrected to 7 400 ppm by volume on a dry basis corrected to 3 percent oxygen
. Formatted Table Merged Cells**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 **298** 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 corrected 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.

.
Mercury 0.000003 lb per MMBtu of heat input. 0.0000048 lb per MMBtu of heat input.

Carbon Monoxide 310 ppm by volume on a dry basis corrected to 7 percent oxygen . 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 **55** of **298**

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 oxygen . 0.03 lb per MMBtu of heat input.

Management Practice Standards (see Table 2 to subpart JJJJJJ )

Carbon Monoxide 100 ppm by volume on a dry basis corrected to 7 percent oxygen . Management Practice Standards (see Table 2 to subpart JJJJJJ )

≥ 10 and < 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 oxygen . 0.07 lb per MMBtu of heat input.

Management Practice Standards (see Table 2 to subpart JJJJJJ )

Carbon Monoxide 100 ppm by volume on a dry basis corrected to 7 percent oxygen . Management Practice Standards (see Table 2 to subpart JJJJJJ ) Merged Cells Formatted Table

Formatted Table**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 **298**
New oil

fired boiler ≥ 30 Particulate Matter

Carbon Monoxide 0.03 lb per MMBtu 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 )

Carbon Monoxide 1 ppm by volume on a dry basis corrected to 3 percent oxygen . Management Practice Standards (see Table 2 to subpart JJJJJJ )

≥ 10 and < 30 Particulate Matter

Carbon Monoxide 0.03 lb per MMBtu 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 )

Carbon Monoxide 1 ppm by volume on a dry basis corrected to 3 percent oxygen . Management Practice Standards (see Table 2 to subpart JJJJJJ ) Formatted Table

Formatted Table**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 **298** Existing coal

- Fired boiler ≥ 10 Mercury 0.0000 03 lb per MMBtu of heat input. 0.000012 lb per MMBtu of heat input.

Existing coal

- Fired boiler ≥ 10 Mercury

Carbon Monoxide 0.0000 03 lb per MMBtu of heat input. 310 ppm by volume on a dry basis corrected to 7 percent oxygen . 0.000012 lb per MMBtu of heat 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 dry 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 subpart JJJJJJ )

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

Formatted Table

Formatted: No underline Merged Cells

Formatted: No underline

Formatted: Indent: Left: 0", Hanging: 0.31", Space Before: 5 pt, Tab stops: 0", Left + 0.29", Left + 0.5", Left + 1", Left + 1.5", Left Formatted: No underline Formatted: Tab stops: 0", Left + 0.29", Left + 0.5", Left + 1", Left + 1.5", Left + 2", Left + 2.5", Left

Formatted: No underline Formatted: Tab stops: 0", Left + 0.29", Left + 0.5", Left + 1", Left + 1.5", Left + 2", Left + 2.5", Left

Formatted: No underline**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 **298**

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 years followin g [ INSERT THE DATE OF PUBLICATION OF THIS FINAL
RULE IN THE FEDERAL REGISTER ]. This final rule requires that 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 OF THIS FINAL RULE 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 fina l rule no later than [ INSERT THE DATE 3
YEARS AFTER THE DATE OF PUBLICATION IN THE FEDERAL REGISTER ]. As under the proposed rule OF THIS FINAL RULE IN THE FEDERAL
REGISTER ]. Under the proposed rule, the owner or operator of a new source would have been required to comply on the date of publication of the final rule or upon startup of the facility, which ever was later. Because this rule is subject to the Congressional Review Act , the owner or operator of a new source is required to comply on [ INSERT THE DATE 60 DAYS AFTER THE DATE
OF PUBLICATION OF THIS FINAL RULE IN THE FEDERAL REGISTER ] or Formatted: Font color: Black**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 **298** upon startup of th e facility, whichever is later. Additionally, we have clarified t he compliance requirements 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 combusting solid waste ), if the effective date is after the applicable compliance date s discussed above

. W e have also re vised the proposed continuous compliance requirement requirement s to be consistent with changes to the emission limits in this final rule, and are no longer requ iring CO CEMS for biomass, oil, and coal

- fired units to be consistent with changes to the emission limits in this final rule . For 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 emission limits. Because b oilers in the biomass and oil subcategories are only required to meet the management practice standards in Table 2 of 40 CFR part 63, subpart JJJJJJ , no testing for CO emissions is required 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 **60** of **298** these units.
G
. Affirmative Defense We have added provisions to this final rule to include an affirmative defense to civil penalties for 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. 11201 , you may assert an affirmative defense for exceedances of such standards that are caused by malfun ction, as defined at 40 CFR 63.2. ( See 40 CFR 63. 1122 6 (def ining “affirmative defense” to mean, in the context of an enforcement proceeding, a response or defense put forward by a defendant, regarding which the defendant has the burden of proof, and the m erits of which are independently and objectively evaluated in a judicial or administrative proceeding). The included provisions specify the elements that 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 technical corrections and clarifications to subpart JJJJJJ . These changes**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 **298** 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 applicability. 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 input ca pacity above 10 0 MMBtu /h are required to demonstrate 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 ,” “Minimum**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 **298** 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 examp le, we revised the definition of

“ boiler B oiler ” to describe 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 “Waste heat boiler” was revised to remove the criteria that 50 percent of total rated heat input capacity had to be from waste gases. supplem ental burners

. We also revised the definition of “Natural gas” to include gas derived from naturally occurring mixtures found in geological formations 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** **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 **298** 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 in 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 MACT 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) requirement s . 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 explicitly 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**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 **298** language of section 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 standards 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, bioaccumulative 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 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 that standards under section 112(d)(2) or (d)(4) are required for the pollutants listed in section 11 2(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 , which 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 **65** of **298** the 112(c)(6) pollutant s that forms form 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 satisf y 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 rational basis or adequate factual justification for the n eed 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 determination that 90.3 percent of the 1990 emissions 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 from promulgating a MACT

- based stand ard 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).**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 **298** 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 under CAA section 112(c)(6) or wheth er 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 NESH AP. 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 threshold for each pollutant. Neverthe less, the docket for this rulemaking contains a 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 provisions at this time for not only mer cury but also and 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**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 **298** 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 surrogate for POM is the limited amount of data available to quantify emissions, emissions and the few EOM inventories or emission factors exist, and in exist ence. Commenters also stated that EOM includes other extractible organi cs in addition to the PAHs. The commenters suggest that the reasonable assumption is that any observed health effects come from the PAH faction f r action 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 the CAA section 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

. re - examination of our section 112(c)(6) baseline inventory for POM. As we noted in the proposed rule, we reexamine the inventory associated with the original listing as we learn more about the source category in the rule development process

. ( 75 FR**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 **298** 31904
. )
. Based on a re - examination of the emission inventory in light of comments , we have determined that we only need ed need to address the coal

- 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 fro m 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 allo wed 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. In the CAA section 112(c)(6) source listing, we used three 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

- based regulations only for coal

- fired area source boilers and w ithout regulating biomass

- fired and oil

-**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 **298** 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 order 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 compiled three separate baseline inventories for POM, one for each 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
. In light of the comment described above regarding EOM, we re

- examined our three section 112(c)(6) obligations baseline inventories for POM.
We For the reason stated below, we have analyzed these comments and determined that EOM should not be used as one of the indicators for POM

. decided to use only the baseline inventory for 16

- PAH in determining the 90 percent threshold under section 112(c)(6). We agree with the commenters who have identified data gaps in our knowledge of what source categories are emitting EOM. There are While we have data on 16

- PAH emissions estimates for 16

- PAH for many more 94 categories than there are estimates for , Formatted: Font color: Auto Formatted: Font color: Auto Formatted: Font color: Auto**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 **298** we only have available data on EOM
. The use of 16

- PAH allows for the most accurate representation of the universe of categories that emit POM and which are needed to meet our 90 percent requirement. T he 16

- PAH inventory has emissions estimates for over four times as 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 incl ude 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 compon ent captured by the other measures of POM or due to non

- POM compounds. In short, we cannot say EOM is a good surrogate for the health effects of POM. In our judgment, t he for 18 source categories. T he lack of available data on EOM emission estimates for EOM creates a distorted picture of the relative contributions of source categories for which there are available EOM estimates data

. The lack of source categories making up the total EOM inventory makes the relative contribution of the few c ategories that do Formatted: Font color: Auto

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Page **71** of **298** have data unrealistically inflated. 2

We have analyzed these comments and determined , considerably fewer than the 94 categories for which we have 16

- PAH data. Because the 16

- PAH inventory allows for the most accurate representation of the unive rse of categories that emit POM, we have decided to use that EOM should not be used as one of the indicators baseline inventory for determining the 90 percent threshold for POM

. Ther efore, we re

- examined the emission inventory u sing PAH (7

- PAH and 16

- PAH) as the indicator

. under section 112(c)(6). Based on this re

examination the baseline inventory for 16

- PAH , regulating POM emissions from area source biomass and oil boilers are not

n eeded to meet the CAA section 112(c)(6) obligations. Thus, POM emissions from area source boilers in the biomass and oil We therefore cannot say with confidence that by using EOM as an indicator the baseline inventory for POM that EOM we are capturing a significant percentage 90 percent of either EOM emitted the baseline P OM emissions, as required by all section 112(c)(6). Similarly, we have data on 7

- PAH for 32 categories or POM emissions.

2 When justifying its use in the 1998 inventory, 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 ) inv entory. Had more data been gathered, perhaps EOM would have proved to be a more useful indicator of POM. However, the anticipated inventory was not developed. Formatted: Font color: Black

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Page **72** of **298** subcategories can be regulated under GACT, instead of MACT

. With respect to mercury and POM from area source boilers classified as bi omass - fired or oil

- fired, as well as with respect to other urban HAP besides POM, we have revised the final rule 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 in the biomass and oil subcategories. The management practice standard for new and existing area source boilers requires the implementation of a tune

- up program. 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 are 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 greater than 10 MMBtu/ hr h (using PM as a surrogate).**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 **298** Emission Standards for HAP Other than Mercury
Comm ent

The commenter said that EPA appears to believe that because area source boiler s are needed only to reach 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 : One commenter stated that CAA section 112(c)(6) provides that EPA must “list categories and subcategories of sources assuring that sources accounting for not less than 90 percent of each [enumerated] pollutant are subject to standards under subsectio n (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 EPA sets standards for area source boilers under section 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.**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 **298** 11 2(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 se ction 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 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 manufacturing because the Agency found no sources using control technologi es for those HAP. In rejecting EPA’s argument, the court stated that EPA has “a Formatted: Font: Not Italic, Underline

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Page **75** of **298** statutory obligation to set emission standards for each listed
HAP.” Id. at 634. The Court noted the list 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. (Emphasis 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 standards for listed source 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 “source s 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 be 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 Formatted: Font: Not Italic, Underline

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Page **76** of **298** Nationa l 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 regulatio n under section 112(d)(2) only of the HAP for which a source category is listed under section 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 mercury and POM emissions. There is 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 Section 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) ob ligations 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 th e source is needed to meet 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 **77** of **298** 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 automatical ly compelling regulation of all HAP emitted by area sources unrelated to the core object of section 112(c)(6), which is control of the specific persistent, bioaccumulative HAP, and thereby bypassing these otherwise applicable preconditions to setting secti on 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
. )
. 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 promulgating 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 pe rsonnel, on the boiler and its energy use systems to identify cost

- effective energy conservation measures. As discussed in the June 2010 Beyond

- the

- floor option**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 **298** proposed rule, a n energy assessment provides valuable information on improving energy efficiency. Owners and operator s 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. 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

. , if implemented

. In this final rule , the energy assessment requirement is both a beyond

- the

- floor control for the MACT

based standards for the coal 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 princip al 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 associated with the energy assessment requirement, therefore it cannot be "beyond the floor;" and 3) the bare**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 **298** requirement to perform an audit without being required to implement its findings is not a standard under CAA section 112(d). With res pect to the first argument, we have carefully limited the requirement to perform an energy audit a ssessment to specific portions of the source that directly affect emissions from the affected source boiler, as indicated by the revised definition of an energy assessment in section 63.11237 of subpart JJJJJJ

. The emissions that are being controlled come from the affected source. For coal

- fi r ed units, the process changes resulting from a change in an energy using system will reduce the volume of emissions at t he 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 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 assessment will generate emission reductions through the reduction in fuel use beyond those required by the floor. While the p recise quantity of emission reductions will vary from source to source and cannot be precisely estimated, the requirement is clearly**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 **298** directionally sound and thus consistent with the requirement to examine beyond the floor controls. By definition, any emis sion reduction would be cost effective or else it would not be implemented. Finally, with respect to the third argument, the requirement to perform the energy audit is, of course, a requirement that can be enforced and thus a standard. As noted, while w e do not know the precise reductions that will occur at individual sources, the record indicates that energy assessments reduce fuel consumption and that parties will implement recommendations from an auditor that they believe are prudent. 3 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 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 Section 112(h) of the CAA

3 C ase studies and success stories highlight ing energy savings achieved by companies that have participated in Save Energy Now energy assessments and used Industrial Technologies Program software tools to improve energy efficiency can be found at http://www1.eere.energy.gov/industry/saveenergynow/case_studies. html and at the Department of Energy’s Energy Assessment Centers Database http://iac.rutgers.edu/database

.**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 **298** the technical and economic limitations on the enforcement of emission standards for boilers with heat input capacity less than 10 MMB tu /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 t he 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 source s 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 st andards only if it is “not feasible to prescribe or enforce an emission standard.... due to technological or economic limitations

. ” Response: EPA disagrees with commenters. As discussed 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 **82** of **298** 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 , ” consistent with the provisions of CAA sections 112(d) or (f), in those cases where, in the judgment of the Adm inistrator, it is not feasible to prescribe or enforce an emission standard. CAA section 112(h)(2)(B) further defines the term “not feasible” to mean when “the application of measurement technology to a particular class of sources is not practicable due t o 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 emission s 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 (less 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 installation of ports into small diameter stacks vents for smaller boilers would likely interfere with the functionality of exhaust systems for new and ex isting 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 **83** of **298** Because many existing area source boilers with a capacity below 10 MMBtu/h generally have stacks with diameters less than 12 inches, and because many 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 emission limits would present an excessive burden for smaller sources. Thus, we are establis hing 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 input capacity of less than 10 MMBTU/h

. De minim i s Levels
Comment: Several commenters stated t hat 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 subject 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 for personal use or seasonal comfort heating. Other commenters noted that State rules that require work practice requirements**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 **298** for boilers all have a lower limit on applicability of typically 1 to 5 MMBtu/ hr h ; these commenters stated that EPA has provided no basis for applying work practice standards 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 institutional 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 boiler s, 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 reason for exempting hot water heaters in the Boiler MACT was that hot water heaters are not part of the 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 **85** of **298** 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 co nsistent 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 determination 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 wh ile 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 in adequate surrogate for POM because there is no POM invariably present in CO; likewise, commenters stated that because CO and POM have different mechanisms of formation and reduction , CO cannot be considered as a reliable surrogate.**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 **298** Several commenters sug gested 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 surrogate for organic HAP emissions in other regulatory efforts, inc luding 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 revised 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
Euro pean study 4

4 EUROPEAN WOOD

- HEATING TECHNOLOGY SURVEY: AN OVERVIEW OF COMBUSTION PRINCIPLES AN D THE ENERGY AND EMISSIONS PERFORMANCE CHARACTERISTICS OF COMMERCIALLY AVAILABLE SYSTEMS IN AUSTRIA, GERMANY, DENMARK, NORWAY, AND SWEDEN ; Final Report ; Prepared for the N ew Y ork S tate E nergy R esearch and D evelopment A uthority; NYSERDA Report 10

- 01; April 2010

. that finds the correlation between CO and POM (or organic HAP, in general) is weaker at lower CO concentrations**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 **298** (less than 100 ppmv) but we did not have the opportunity to examine the data relied on by the study and no data supporting this supp osition 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. EP A 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 proposed CO limits are u nachievable 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 m easurement, 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 higher emissions of NO x . Other commenters suggested that the CO emission limits should be determined using long

- term CEMS data to account 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 **88** of **298** natural variability in CO emissions . Commenters also offered alternatives for control of POM . One commenter suggested 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 meth odology , the final C O emission 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 l ong - 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**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 **298** operating cycle of typical industrial, commerci al, and institutional boilers

. 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 subcategory 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 design 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 Institutional 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 a rea 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**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 **298** rejected the pollutant

- by

- pollutant approach on the basis that both PM and CO emission limits are not achievable even for the best performing sou rces. 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 the population of units for both the PM and CO emission limits, an d 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 stated 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 stated 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**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 **298** MACT floor. See, e.g., Brick MACT , 479 F. 3d at 880

– 81, 882

– 83;
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 calcula ted 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.
A mong 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 need 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 applica ble case law in developing its floor methodology. Although i ndustry commenters maintain these

sources can not meet the standards , which are predicated on their**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 **298**

own perf ormance without adding controls, t his contention lacks a basis in the record. For mercu ry, 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 those 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 inform ation 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 i t 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 are similar in size and operation to major source boilers; o ne 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**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 **298** significantly flawed because they are based on inadequate data and not representative of the un its 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 boilers, 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 expressed that EPA must include emissions data collected by S tate s tate 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 "gaps" 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 the 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**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 **298** also stated that EPA has not justified using three times the detection level in its analysis. These commenters stated that this method biases the results towards higher HAP emissions, results in a hypothetical stan dard 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 da ta sets, the final emission limits 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 information 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 determined 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 forth in CAA section 112(c)(6) for POM. 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 **95** of **298** emissions limits for CO for coal

- fired boilers were based on the available information from the ICR and state operating permits , as well as that received in comments. EPA d isagrees with commenters who stated that we excluded emissions data collected by State s tate and local permitting authorities in establishing the MACT floor

. The available
S tate s tate permits obtained for coal

- fired area source boilers limiting CO emissions were for 11 units located in Ohio (3 units), and Illinois (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 sources, the emission data on these five boilers is from emission sources in the area source coal

- fired boiler subcategory. With respe ct to non

- detect data, EPA considered and accounted for non

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

- fired boilers in this final rule

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

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

- detect values, the inherent**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 **298** imprecision in the pollutant measurement method has a large influence on the reliability of the data und erlying 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. T he confidence level that a value, measured at the detection level is greater than zero, is about 99 percent. The expected measurement 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 the
method detection level. 5 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 identi fy 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

5 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 **97** of **298** the advantage of relying on the data collected to develop the MACT floor emis sion 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 detecti on 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 detect ion 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 ti mes 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 herefore T herefore, we revised the approach we used for the proposal and, for the final rule , 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**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 **298** floor emission limit for mercury accounts for measure ment variability and imprecision. Variability
Comment: Numerous commenters stated that the floor 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 per cent. These commenters stated that while EPA can consider 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 ac count for differences in performance between sources except 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 methodology 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 than the average level of the best 12 percent. Commenters further stated that EPA erred by relying 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 **99** of **298** 99 percent UPL only to reflect variability. Some commenters stated that EPA must collect and consider data on additional variability, such as that related to variab le fuel quality or longer term variability, to supplement its analysis. These 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 foreseeable circumst ances” 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 p opulation

. 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 achieved by th e 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). Furthermore,
CAA section 112(d)(3) includes a provision stating that the MACT floor for existing sources cannot be less stringent than “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 **100** of **298** average emission limitation achieved by the best

- performing 12 percent of the existing sources (for which the Administrator has

e missions information).” We see no statutory prohibition in considering inter

- source variability of the best performing sources (which is all our floor calculation does, by considering the pooled variability of the best performing sources). Section 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 must account fo r 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 performing sourc es by taking the pooled average of the best performing sources' variability. This is an aspect of identifying the average performance of those sources.**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 **298** Furthermore, EPA is confident that the UPL is an appropriate statistical tool to use in determining 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 a confidence interval covers a population parameter w ith 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., That is, c onfidence limits are limits within which we expect a given population parameter, 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 fal l 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 level. 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 percentile , Formatted: Not Superscript/ Subscript, Raised by 3 pt**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 **298** 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 observation from a population. In other words, the prediction 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 av erage) 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 revi sed 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 ha s 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 determi ned to be lognormally distributed, EPA also considered the commenters suggested**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 **298** 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 EPA considered a scale bias correction approach as well as a new UPL equation based on a Bhaumik and Gibbons 2004 paper, which calculates “An Upper Prediction Limit for the Arithmetic Mean of a Lognormal Random Variable 6

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

- based 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 re presents emission 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. Furt her, for fuel based ”. Given data availability, EPA sel ected the Bhaumik and Gibbons 2004 approach which addresses commenters concerns with the proposed computations.

6 Bhaumik, D. K. and R. D. Gibbons. 2004. An Upper Predicti on 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 **104** of **298** 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 mitiga te, to some degree, the variability in emissions that can be expected. 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 confidence 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 determined 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 bo iler design 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 Ju ne 2010 proposed rule, EPA attempted to assess the impact of fuel variability 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 **105** of **298** 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 of mercury contained in the fuel. For this final rule , we have implemented a fuel variability factor into the mercury emission 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 a lso note that fuel usage can be reduced by improving the combustion efficiency 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. Be yond the Floor Analysis
Comment: Several commenters objected to EPA's beyond

- the

floor determination for new area source boilers. Many of 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 **106** of **298**
commenters stated that the beyond the floor approach must consider fuel switching as an option. Other comment ers objected to EPA's beyond

- the

- floor determination for existing boilers, specifically stating that EPA should require existing facilities to either comply with emission limits for larger units , or require fuel switching to the cleanest fuel in their clas s (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 ach ievable option. Commenters debated EPA's stated concerns regarding fuel 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 switching would be an appropriate control option for sources in each subcategory under the proposed rule, including**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 **298** the feasibility of fuel switching to other fuels used in the subcategory and to fuels from other subcategories. This consideration included determining whether switching fuels would achieve lower HAP emissions. We also gave consideration to whether fuel switching could be technically achieved by boilers in the subcategory co nsidering the existing design of boil ers and the availability of various 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 based 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 co ncerns 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 Assessments
Comment: Several commenters disagreed with EPA's determination to require energy assessments as a beyond 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 **108** of **298** floor option

. Commenters specifically stated that EPA cannot require an energy assessment because an assessment is not an emission standard 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 stringen t enough; these commenters stated that a n energy
assessment cannot impose standards 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 implemented 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

r equirements were "too broad" or "too intrusive

. " Commenters were concerned that the energy assessment would include not only than the affected source, but also the entire facility, which EPA does not have the authority to regulate. Response: EPA disag rees with commenters that state 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 **109** of **298** EPA does not have the authority to require an energy assessment.

A n ener gy assessment is an appropriate beyond

- the

- floor control technology because it is one of the measures identified in CAA section 112(d)(2). CAA se ction 112(d)(2) states that “Emission standards promulgated ... and applicable to new or existing sources ... is achievable ... through application 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 conservation measures (such as, process changes or other modifications to the facility) that can be implemented to r educe the facility energy demand which would result in reduced fuel use. Reduced fuel use will result in a corresponding reduction**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 **298** 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 the 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 clarify 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 requirements, 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**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 **298** those portions of the facility using steam the energy generated from the af fected boiler system. Additionally, a facility may elect, but is not required, to implement the cost

- effective energy conservation measures identified in the energy assessment. Because we lack 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 conservation measures identified in the energy assessment. EPA notes that t he cost of an energy

ass essment 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 energy 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 conservati on 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 capacity greater than 10 MMBtu/h as a beyond**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 **298** the floor option or GACT
. EPA disagrees with c ommenters 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 process which involves a thorough examination of potential savings from energy efficiency impro vements, pollution prevention, and productivity improvement. It leads to the reduction of

p ollutants through process changes and other efficiency modifications. I mproving 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) from 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

a ppropriate 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 heat input capacity of greater than 10 MMBTU/h , rather than focusing on**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 **298** smaller boilers

. W e also examined other emission measures currently in place. EPA did not have sufficient information to determine if requiring an energy assessment for area boilers with a heat input capacity of less than 10 MMBtu/h is economically feasible. For boilers w ith a heat input capacity less than 10 MMBtu/h, the data that we have suggests that area source boilers typically conduct boiler tune

- ups. We also examined work practices listed in State state regulations for area source boilers with a heat input capacity less than 10 MMBtu/h . These regulations included tune

- ups ( 10 States states ), operator training (one State state ), periodic inspections (two
States states ), and operation in accordance wit h manufacturer specifications (one State state ). When energy assessment s 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 manufacturing facilities. 7

7 C ase studies and success stories highlight ing energy savings achieved by companies that have participated in While the efficiency gains may be somewha t less when the assessment is mandated for a source rather than voluntary, the absence of a

energy assessments can be found at http://www1.eere.energy.gov/industry/saveenergynow/ca se_studies. html and at the Department of Energy’s Energy Assessment Centers Database http://iac.rutgers.edu/database

.**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 **298** 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 e mission 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 with a heat input capacity greater than 10 MMBtu/h, and requir e area source boilers in the biomass and oil subcategories with a heat input capacity of greater than 10 MMBtu/h to meet the management practice standard of a tune

- up. These requirements represent the generally available and cost

- effective pollution reduc tion 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
. Other 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**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 **298** typically include schools, small businesses, hospitals, and other institutions in ru ral areas. Some commenters stated that the CO emiss ion 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 considered commenter's concerns. CAA section 112(d)(5) al lows the Administrator, with respect to area sources, to promulgate standards which provide for the use of generally available control technologies or management practices to reduce emissions of HAP
. Therefore, w ith respect to mercury and POM from area so urce 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 revised the standards for area source boilers c lassified in the biomass and oil subcategories

. Rather than require a numeric MACT emission limit for POM , new 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 **116** of **298** existing area source boilers in the biomass or oil subcategories
must meet the r equirements of GACT, 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 limits. P M is used a s a surrogate for urban metals , which we are required to regulate 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 for new area source boilers. Additionall y, 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 performance testing. Furthermore, new co al

- 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**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 **298** 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 been 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. EPA has determined that the promulgated numeric emission limits for PM are appropriate GACT standards for new area source boiler s 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 NO x emissions, reduce combustion Formatted: Lowered by 3 pt**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 **298** efficiency, and/or increase fuel use. Commenters noted that many typical tune

- up requirements, including States ' s tates ' requirements, are aimed at minimiz ation 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
NO x . Multiple commenters requested that EPA specify that tune

ups consider optimizing efficie ncy and limiting increases of
NO x , and not only require minimizing CO

. Other commenters requested that EPA allow the use of portable instruments to measure CO for the tune

- up requirements

. Several commenters requested that EPA clarify 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 requiring
tune

- ups as a w ork 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 tune

- up designed to specif ically 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 Formatted: Lowered by 3 pt

Formatted: Lowered by 3 pt**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 **298** 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 boilers may have combustion efficiencies of 60 percent or lower. Furthermore, as the combustion efficiency decreases, fuel usage increases to maintain energy output resulting in increased emissions. A tune

- up performed to the manufacturer's specifications would 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 increase emissions of NO X . Therefore, the 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 after adjustments are

ma de 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 instruments**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 **298** are permissib le 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 unlawful and arbitrary because they are not based on different classes, types, or sizes. At least one commenter specifically stated that the proposed subcategorization defied the explicit recommendation of the Small Entity Representatives ( SERs ) to the Small 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, agricultural

res idue, 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 subcategories a pplied to major sources should be used for area

sources. Response: EPA disagrees with commenters

. The Section 112(d)(1) of the CAA allows EPA to divide source categories Formatted: Widow/Orphan control**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 **298** into states “the Administrator may distinguish among classes, types, and sizes of so urces within a category or subcategory” in establishing emission standards. Thus, we have discretion in determining appropriate subcategories when based on classes, types, and sizes of sources. We used this discretion in developing subcategories for the boiler are a source category. Through subcategorization, we are able to define subsets of similar emission sources within a source category if differences between given types of units lead to corresponding differences in the nature of in emissions or the cha racteristics, technical feasibility of applying emission control techniques , or opportunities for pollution prevention exist within the source category
. The design, operating, and emissions information that EPA reviewed during the area source rulemaking i ndicates the need to subcategorize based on boiler design 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 rule, boiler systems are designed for speci fic 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**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 **298** 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 t he 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 sub categorizing them by fuel type is appropriate. Additionally, 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 we lack the same level of detail for the area source category, EPA has determined that it would be inappropriate to establish the same subcategories for major and area s ource boilers. However, a s discussed in the comments below, we have**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 **298** 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 , r ather than the actual fuel that the boiler is combusting. Finally , as discussed earlier in this section, we have revised the MACT and GACT limits for the coal, oil, and biomass subcategories in this final rule

. Existing o il and biomass

fired boilers ar e 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 sta ndards. While more stringent limits under this final rule may have required subcategories based on the size of the unit, EPA has determined that the subcategories chosen are reasonable based on the applicable req uirements of this final rule

. Combustion of Secondary Fuels**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 **298** Comment: Multiple commenters sought clarity for the combustion of secondary materials and/or alternative 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 boilers. 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. Many 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 commenters expressed concern regarding “combination boilers” (boilers that co

- f ire coal in an amount greater than 10 percent heat input basis with at least 10 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 o f
gas - fired boilers should allow for units burning less than 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 **125** of **298** percent liquid fuels. Many of the commenters suggested alternative definitions for the proposed subcategories or provided alternative thresholds. Alternatively, there were some commenters w ho 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 de tailed 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 clarify each subcategory in order to account for the combustion of an array of secondary fuels. Area source boilers combusting coal, biomass or oil may also combust se condary materials as part of their fuel mix . It was not our intent to exclude**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 **298** boilers combusting these non - hazardous secondary materials that do not meet the definition of "solid waste" from the coal, biomass or oil

- fired subcategories. 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 combination

w ith 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 , but
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 combusting at le ast 15 percent of biomass. This definition differentiates these primarily biomass

- fired boilers from the coal subcategory. Additionally, t he o il subcategory has been revise d to include boilers that burn any liquid fuel but are not included in either the coal or biomass subcategories

. Based on new data submitted during the public comment period, EPA has determined that area source boilers may combust**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 **298** secondary materials. Data submitted indicates that as much as 15 percent of secondary materials , or alte rnative 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 organic

HAP
. due to the higher moisture content of biomass compared to fossil fuel

. 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 and accoun t 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, including limi ted 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 EPA is not justified in providing an exemption for gas

- fired boi lers. Response: As noted in Section VII of the proposed June**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 **298** 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), 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 ie s

“ subject to regulation ” 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 this 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 se ction 112 MACT standard

. (See 40 CRF part 63, subpart MM)

. Conversely, 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 category l isting for CAA section 112(d)(2) and emit the pollutants identified in CAA section 112(c)(3). As discussed above, EPA has set appropriate MACT and GACT limits to 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 **129** of **298** 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 boilers 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 limits during SSM directly conflicts with the requirement that MACT be achievable and is technically feas ible ; therefore EPA could not require emission limits during periods of SSM. Some commenters requested a separate standard for CO for startup ; a t least one 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 and shutdown . The commenter therefore concluded that requiring a CO emission limit during startup and s hutdown would not only be technically unachievable, but w ould promote unsafe and improper operation

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

. 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 **130** of **298** commenters specifically objected to EPA's decision to base the SSM requirements on data from the proposed major source NESHAP for industrial, commercial, 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 has revised this final rule to incorporate a work practice standards standard 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 boilers and determined that requiring CO CEMS for units with heat input capacities greater or equal to 100 MMBtu/hr was reasonable. However, EPA has revised this final rul e to only require emission limits for mercury and CO for coal

- fired boilers. Furthermore, we are only requiring sources to perform a work practice standards, including standard, following 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. Based on the available dataset for facilities in the affected area source category, EPA determined that there are currently no existing coal

- fired boil ers with a 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 **131** of **298** capacity greater than 100 MMBtu/h located at area sources. Coal

- fired boilers with a heat input capacity of greater than 50 MMBtu/h are generally major sources of HAP. Therefore, requiring CEMS for boilers of this size is unnecessar y for the defined source category. In lieu of CEMS, we also considered whether requirements for performance testing would be feasible for area source boilers during periods of startup and shutdown. Upon review of these requirements, EPA determined that it is not feasible to require stack testing

- in particular, to complete 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, a separate sta ndard 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 viewed as a distinct operating mode and, therefore, any emissions that occur at s uch 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 of this preamble, EPA has added to this final rule an affirmative defense for civil penalties for exceedances 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 **132** of **298** numerical emission limits that are caused by malfunctions. Therefore, as allowed under CAA section 112(h), we are requiring a work practice st andards standard for all coal

- fired area source boilers during periods of startup and shutdown. The work practice standards include standard require s following the boiler manufacturer's specifications for periods of startup and shutdown.
H. Compliance Req uirements Rationale for Demonstrating Compliance
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 according 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 discussed in Section VI .E of this preamb le. EPA has determined that e xisting Formatted: Indent: First line: 0", Widow/Orphan control**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 **298**

sources subject 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 ]. one year after publication of th is final rule

. 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 later than [ INSERT THE DATE 3 YEARS AFTER THE
DATE OF PUBLICATION IN THE FEDERAL REGISTER ]. 3 years after publication of the final rule

. Section 112(i)(3)(B ) allows EPA,

on a case - by

- case basis to grant an extension permitting an existing source up to one additional year to comply with standards if such additional period is necessary for the installation of controls. The EPA feels that this provision is suff icient for those sources where the 3

- year deadline would not provide adequate time to retrofit as necessary to comply with the requirements of the standard.
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**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 **298** 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 signifi cant regulatory burden

. Several commenters stated that the proposed testing 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 sourc e 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 emission 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 determin ed that requiring CO CEMS for units with heat input capacities greater or equal to 100 MMBtu/h was reasonable. However, based on a review of the available**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 **298** dataset for facilities in the affected area source category, we have determined that there are curre ntly 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 bi omass and oil subcategories with a heat input capacity greater than 10 MMBtu/h are not required to meet emission limits for CO in this final 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 mpacts
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 biomass 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 filters alone will be sufficient for area source coal

- fired boilers to meet the proposed mercury limit

.**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 **298** Response: In light o f 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 of greater than 10 MMBtu/h; smaller boilers must only meet the management practice standard of a tune

- up. These changes hav e significantly decreased the costs presented in the proposed June 2010 rule. Additionally, commenters provided additional cost information during the public comment period; EPA has inc or p o r ated this information into the analysis for this final rule . Bas ed 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. Furthermore, new coal

- fired area source boilers will likely require a PM control device to comply with the proposed mercury

M ACT standard and required performance testing. W e determined**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 **298** in the context of the major source rulemaking, and from further analysis 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

. Comment: Some commenters stated that this final rule would have substantial impacts on rural communities. Commenters noted that m any rural communities rely upon or significantly benefit from the use of biomass boilers for energy at manufacturing fac ilities, schools and hospitals. These commenters stated that
t he proposed rule will negatively impact both boiler owners and fuel suppliers 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 biomass

- fired area source boilers, we believe these concerns are no longer an issue. Ex isting In the final rule,

e xisting biomass area source boilers are only subject 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 **138** of **298** 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 as sessment performed. There are no testing or monitoring requirements in this final rule for existing biomass

- fired area source boilers. For a typical existing biomass

- fired boilers, this change resulted in reducing the annualized cost of compliance from a bout $420,000
to about $2,200. New biomass

- fired area source boilers with a heat input capacity of 10 MM Btu/h or greater are only subject to a PM emission limits which requires an annual PM test be conducted.
**VI .**  **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 standa rds under
CAA s ection 112(d)(2) or 112(d)(4). EPA has identified “Industrial Coal Combustion,” “Industrial Oil Combustion,” Industrial Wood/Wood Residue Combustion,” “Commercial Coal Combustion,” “Commercial Oil Combustion,” and “Commercial Wood/Wood Resi due Combustion” as source categor ies that emit two of the seven CAA s ection 112(c)(6) pollutants: POM and 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 **139** of **298** (The POM emitted is composed of 16 polyaromatic 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 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

- c ombustion controls. The add

- on PM control systems (fabric filter) used to reduce mercury and/or
PM emissions further reduce emissions of these organic pollutants, 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 Formatted: Font: Not Italic, Underline**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 **298** is, therefore, reasonable to conclude that POM emissions from coal

- fired area source boilers will be substan tially controlled. In lieu of establishing numerical emissions limits for pollutants such as POM, we regulate surrogate substances. While we have not identified 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 surrogate for control of POM, such that it is not necessary to establish numerical emissions limits fo r 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 an energy assessment provision that encourage s modifications to the facility to reduce energy deman d that lead to these emissions.

**V I**  **V I**  **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**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 **298** 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

m etals, 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. Emis sions 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 of improved combustion and reduced fuel

use. POM re ductions are represented by 7

- PAH, a group of polycyclic aromatic hydrocarbons. EPA estimates that the energy efficient work and practices, management practices , and CO emission limits may reduce emissions of 7

- PAH by 8 tpy for existing units 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**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 **298** reductions is presented in “Estimation of Impacts for Industrial, Commercial, and Institutional Boile rs 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, nickel, 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 amo unt.
B. What are the cost impacts ? 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 boiler to each existing uni t based on the fuel, Formatted: Left
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Formatted: Left**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 **298** 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 stand ards. 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 Subcategory**  **Estimated/ Projected No. of** 

**Affected Units Total**  **Annualized Cost**  **(TAC) (**  **$ 10**  **6 /yr)**  **a** Existing Units Coal 3,710 37 Biomass 10,958 24 Oil 168,003 374 Facility Energy A ssessme nt All 52

New Units b Coal 155 0.4 Biomass 200 2.6 Oil 6,424 45 Formatted: Left
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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 sources 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 discussion 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 ? The economic impact analysis ( 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. En ergy prices will not 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 **145** of **298** 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 bil lion 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 analysis for impa cts 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 Regulatory Flex ibility 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

. The IRFA is discusse d in section 5.2 of the report “Regulatory Impact Analysis: National Emission Standards for Hazardous Air Pollutants for Industrial, Commercial, and Institutional Boilers and Process Heater” located in the docket

. For this RIA employment impacts are modele d based on**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 **298** 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 components of the employment change in r esponse 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 exam ple, 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 increased abatement expenditures generally do not cause a sig nificant 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 (statistically insignificant) net increase of 1.5 jobs. Furthermore t hey find that for two of the industries (pulp and paper, and steel) additional abatement spending leads to a statistically positive, yet quite small, net increase in jobs**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 **298** due to substituting labor for other inputs and relatively inelastic estimated demand for their output. 8 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. Employment 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 increase. Similarly, employment in industries that are complemen ts 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 Kurlansky (EPA) from: Jason Pric e, Nadav Tanners, and Jim

8 These results are similar to Berman and Bui (2001) who find that while sharply increased 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 **148** of **298** 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 thre e 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 complete 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 expenditures) 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 demand effect ( −3.56 jobs per million ($1987) of environmental compliance expen diture) by the total environmental**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 **298** compliance expenditures used in the partial equilibrium model. For example, the jobs effect estimate for the major source rule is estimated to be about 6,000 jobs ( −3.56 × $2,700 million × 0.60). 9 Demand effect results are provided in Table 5

. 10

**Table 5. Job Losses/Gains Associated**  **with the Rules**

**Method 1,000 Jobs**  **Literature -**  **based estimate (net effect [A + B +C below])**  **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 (

- 1 to 2)

9 Since Morgenstern’s analysis reports environmental expenditures in $1987, we make an inflation adjustment the engineering cost analysis u sing GDP implicit price deflator (64.76/108.48) = 0.60) 10 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. Th ese 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 4000 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 estimate 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 parameters of 7000 jobs lost. Formatted: Font: Courier New, 10 pt Formatted: Font: Courier New, 10 pt
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Formatted: Font: Courier New, 10 pt**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 **298**
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 associated 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 Morgenstern et al. paper provides information about the potential job effects of environmental protection programs, there are several qualifications EP A considered as part of the analysis. First, EPA has used the weighted average parameter estimates for a narrow set of manufacturing industries Formatted: Font: Courier New Formatted: Font: Courier New Formatted: Font: Courier New Formatted: Font: Courier New**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 **298** (pulp and paper, plastics, petroleum, and steel). Absent other 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, w e 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, Morgenste rn et al. identifies the industry average as economically and statistically insignificant effect (i.e., the point estimates are small, measured imprecisely, and not distinguishable from

zero )
. EPA acknowledges this fact and thus has reported the 95
percen t 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 th at plant's total costs relative to the aggregate industry costs. By transferring the estimates, EPA assumes a similar distribution of regulatory costs by plant size and that the regulatory burden does not disproportionately fall**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 **298** on smaller plants. Fifth, there are two categories of job effects which are beyond the scope of Morgenstern et al.’s study. One is employment at firms that manufacture pollution control equipment or provide consulting services to design and/or installation pollution control equip ment. 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 com plementary products. However, EPA does not currently have sufficient information to provide estimates of job gains from these sources for these particular rules

. D. What are the benefits ? We estimated the The benefit categories associated with the emissi on reduction anticipated for thi s rule can be broadly categorized as those benefits attributable to reduced exposure
to hazardous air pollutants ( HAPs ) and those attributable to exposure to other pollutants. Because we were unable to monetize the be nefits associated with reducing HAPs, all monetized benefits reflect improvements in ambient PM 2.5 and ozone concentrations. This results in an underestimate of the total monetized benefits. We estimated the total monetized benefits**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 **298** of this final regulat ory 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 an d premature mortality supplied by experts, higher and lower benefits estimates are plausible, but most of the expert

- based estimates fall between these two estimates. 11

**Table 6**  **. Summary of the Monetized Benefits Estimates for the Final Boiler Area Source Rule (millions of 2008$)**  A summary of the monetized benefits estimates at discount rates of 3 percent and 7 perc ent are provided in Table 6 of this preamble. A summary of the avoided health benefits are provided in Table 7 of this preamble.

**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 fine particles are assumed to have equivalent health effects. Benefits from reducing HAP are not included. These estimates do not incl ude energy disbenefits valued at less than $1 million. These benefits reflect existing boilers and 6,779 new boilers anticipated to come online by 2014. **Table 7**  **. Summary of the Avoided Health Incidences for the Final**

11 Roman et al, 2 008. 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. Formatted: Font: Bold Formatted: Centered Formatted Table Formatted: Not Superscript/ Subscript, Lowered by 3 pt Formatted: Not Superscript/ Subscript, Lowered by 3 pt**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 **154** of **298 Boiler MACT** 
**Avoided Health Incidences**  **Avoided Premature Mortality** 24 to 61 **Avoided Morbidity** Chronic Bronchitis 17 Acute Myocardial Infarction 40 Hospital 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 Lower Respiratory Symptoms 460 Upper Respiratory Symptoms 350

1 All Note: 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 existin g boilers and 6,779 new boilers anticipated to come online by 2014. These quantified 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 a s 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 monetized benefits
base d on changes in air quality. This approach is consistent Formatted Table

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Formatted: Not Superscript/ Subscript, Lowered by 3 pt**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 **298** with the recently proposed Transport Rule RIA. 12 For this final rule, we have expanded and updated the analysis since the proposal in several important ways. Using the Comprehensive Air Quality Mo del 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 estimates that are more appropriate for ch aracterizing 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 P M 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 reductions to create the boil er
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

12 U.S. Environmental Protection Agency, 2010. RIA for 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 **156** of **298** because there is no clear scientific evidence that would support the dev elopment 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 benefit

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
because sulfat e 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 to 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 emissions. Altho ugh we are unable to model mercury methylation and human consumption of mercury

contaminated fish, the mercury deposition maps provide an Formatted: Not Superscript/ Subscript, Lowered by 3 pt

Formatted: Not Superscript/ Subscript, Lowered by 3 pt Formatted: Not Superscript/ Subscript, Lowered by 3 pt Formatted: Not Superscript/ Subscript, Lowered by 3 pt Formatted: Not Superscript/ Subscript, Lowered by 3 pt Formatted: Not Superscript/ Subscript, Lowered by 3 pt

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Formatted: Not Superscript/ Subscript, Lowered by 3 pt Formatted: Not Superscript/ Subscript, Lowered by 3 pt**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 **298** improved qualitative characterization of the mercury benefits associated with this final rulemaking. For context, i t 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 (epid emiological) 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,
one based on the American Canc er Society cohort study 13 and the extended Six Cities cohort study. 14

EPA strives to use the best available s cience 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 In the RIA for this rule, which is available in the docket, we also include benefits estimates derived from expert judgments and other assumptions.

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

- term Exposure to Fine Pa rticulate Air Pollution.” Journal of the American Medical Association 287:1132

- 1141
. 14 Laden et al, 2006. “Reduction in Fine Particulate Air Pollution and Mortality.” American Journal of Respiratory and Critical Care Medicine. 173: 667

- 672
. Formatted: Not Superscript/ Subscript, Lowered by 3 pt**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 **298** scientific advice, we have determined that the no

- th reshold 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 assessment
. 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 quality
concentrat ions. 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 . Using 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 important, 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 Formatted: Not Superscript/ Subscript, Lowered by 3 pt Formatted: Lowered by 3 pt**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 **298** shows that the great majority of the impacts occur at higher
exposures. It should be emphasized that the monetized benefits estimates provided above do not include benefits from several important benefit categories, including reducing other air pollutants, ecosystem effects, and visibility impairment. The benefits from red ucing 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. Specifically, we were unable to estimate the benefits associ ated with HAPs that wou ld be reduced as a result of thi s rule due to data, resource, and methodology limitations. Challenges in quantifying the HAP benefits include a lack of exposure

- response functions, uncertainties in emissions inventories and backgrou nd levels, the difficulty of extrapolating risk estimates to low doses , and the challenges of tracking health progress for diseases with long latency periods

. Although we do not have sufficient information or modeling available to provide monetized estima tes 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.**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 **298** In addition, the monetized benefits estimates provided in Table 6 do not reflect the dis benefits 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 percent discount rate (average). CO 2 - related disbe nefits 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 monetized 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. Howev er, 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 levels.
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 ?**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 **298** EPA estimated that no additional water usage would result from the MACT floor 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 waste that wou ld 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 ins talled 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 f rom

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 Institutional Boilers Area Source NESHAP” in the Docket.

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**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 **298** of this rule. The increase results from the electricity 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 control 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. Additionally, 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 faci lities can save 20 trillion B tu of fuel each
year. 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 practice standards will achieve 1 percent improvement in 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**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 **298** 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,” “Indu strial Oil Combustion,” Industrial Wood/Wood Residue Combustion,” “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 polyaromatic 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 1 0, 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

“ sub ject to regulation ” for purposes of CAA s ection 112(c)(6) with respect to the CAA s ection 112(c)(6) pollutants that these units emit. Specifically, as by

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

Formatted: Font: Not Italic, Underline**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 **298** 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 pollutants, 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, therefore, 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 identified 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, w e have concluded that the emissions limits for CO function as a surrogate for control of POM, such that it 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).**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 **298**
To further address POM and mercury emissions, th is rule also includes an 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 s tate , 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 is contained in the Regulatory Impact Analysis (RIA) report. For more information on the costs and benefits for this rule, please refer t o Section VI.C of this preamble see the following table

. Formatted: Normal, Indent: First line: 0.5", Line spacing: Double

Formatted: Font color: Black**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 **298**

**Summary of the Monetized Benefits, Social Costs, and Net B**  **enefits for the Boiler Area Source Rule in 2014 (millions of 2008$)**  **1 3% Discount Rate**  **7% Discount Rate Final MACT/GACT Approach: Selected**  Total Monetized Benefits 2 $210 to $520 $190 to $470 Total Social Costs 3 $490 $490 Net Benefits −$280 to $30 −$300 to −$20

Non

- monetized Benefits 1,100 tons of carbon monoxide 340 tons of HCl 8 tons of HF 90 pounds of mercury 320 tons of other metals <1 gram of dioxins/furans (TEQ) Health effects from SO 2 exposure Ecosystem effects Visibility impairment **Proposed MACT Approach: Alternative** Total Monetized Benefits 2 $200 to $490 $180 to $440 Total Social Costs 3 $850 $850 Net Benefits −$650 to −$360 −$670 to −$410 Non

- monetized Benefits 1,100 tons of carbon monoxide 340 tons of HCl 8 tons of HF 90 pounds of mercury 320 tons of other metals <1 gram of dioxins/furans (TEQ) Health effects from SO 2 exposure Ecosystem effects Visibility impairment 1 All estimates are for the implementation year (2014), and are rounded to two significant figures. These results include units anticipated to come online and the lowest cost disposal assumption. 2 The total mo netized benefits reflect the human health benefits associated with reducing exposure to PM 2.5 through reductions of directly emitted PM 2.5 and PM 2.5 precursors such as SO 2 . It is important to note that the monetized benefits include many but**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 **298** not all health effects associated with PM 2.5 exposure. Benefits are shown as a range from Pope et al. (2002 ) to Laden et al. (2006 ). These models assume that all fine particles, regardless of their chemical co mposition, 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. These estimates include energy disbenefits valued at less tha n $1 million. 3 The methodology used to estimate social costs for one year in

the multimarket model using surplus changes results in the same social costs for both discount rates.
B. Paperwork Reduction Act The information collection requirements in this rule have been submitted for approval to OMB under the Paperwork Reduction
Act , 44 U.S.C. 3501 et seq . 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 are based on the information collection requirements in EPA’s NESHAP General Provisions (40 CFR part 63, subpart A). Th e recordkeeping and reporting requirements in the General Provisions are mandatory pursuant to CAA section 114 (42 U.S.C. 7414). All information other than emissions data submitted to EPA pursuant to the information collection requirements for which a cla im 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 **168** of **298** 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 work practices and management practices in their Notifications of Compliance Status. Recordkeeping is required to demonstrate compliance with emission limits, work practices,

ma nagement practices, monitoring, and applicability provisions. New affected facilities are required to comply with the requirements for startup, shutdown, and malfunction reports and to submit a compliance report if a deviation occurred during the semiannu al reporting period. The annual monitoring, reporting, and recordkeeping burden for this collection (averaged over the first 3 years after the effective date of the standards) is estimated to be $ 407 million. This includes 2.7 million labor hours per yea r at a cost of $254 million and total non

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

- up, semiannual

excess e mission reports, maintenance inspections, developing a monitoring plan, notifications, and recordkeeping. Monitoring, testing, tune

- up and energy assessment costs were also included**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 **298** in the cost estimates presented in the control cost impacts estimates in Section VII.B of this preamble

. The total burden for the Federal f ederal government (averaged over the first 3 years 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 unless the collection displays a currently valid OMB control number. The OMB control numbers for EPA’s regulation s 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 requirement s contained in this final rule.
C. Regulatory Flexibility Act (RFA) , as Amended by the Small Business Regulatory Enforcement Fairness Act of 1996, 5 U.S.C. 601 et seq. The RFA generally requires an agency to prepare a regulatory flexibility analysis of any rule subject to notice and comment rulemaking requirements under the Administrative Procedure Act or any other statute unless the agency certifies Formatted: Font color: Black Formatted

Formatted: Underline, Font color: Black

Formatted: Font: 12 pt, Font color: Black Formatted: Normal, Line spacing: Double**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 **298** that this final the rule will not have a significant economic impact on a substantial number of small entities. Small entities include small businesses, small organizations, and small governmental jurisdictions. For purposes of assessing the impacts of today’s rule

on sma ll entities, small entity is defined as: (1) a small business according to Small Business Administration (SBA) size standards by the North American Industry Classification System category of the owning entity. The range of small business size standards fo r the affected industries ranges from 500 to 1,000 employees, except for petroleum refining and electric utilities. In these latter two industries, the size standard is 1,500 employees and a mass throughput of 75,000 barrels/day or less, and 4 million kil owatt

- hours of production or less, respectively; (2) a small governmental jurisdiction that is a government of a city, county, town, school district or special district with a population of less than 50,000; and (3) a small organization that is any not

- for

- profit enterprise which is independently owned and operated and is not dominant in its field. Pursuant to section 603 of the RFA, EPA prepared an initial regulatory flexibility analysis (IRFA) for the proposed rule (see Formatted: Font: 12 pt, Font color: Black

Formatted: Font color: Black

Formatted: body text,bt,body tx,indent,flush,memo body text,body 4h,body 4equationh, Line spacing: Double**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 **298** 75 FR 31896 ( June 4, 2010 )). Purs uant to section 609(b) of the RFA, EPA and convened a Small Business Advocacy Review Panel to obtain advice and recommendations from of representatives of the regulated small entities that would potentially be regulated by this final rule

. . A detailed discu ssion of the Panel’s advice and recommendations is found in
the final Panel Report located in the docket. (Docket ID No. EPA

- HQ

- OAR

2002

- 0058

- 0797). A summary of the Panel’s recommendations is
also presented in detail in the preamble to the proposed rule

. See 75 FR 3191 8

- 31918 at 75 FR 32044

- 32045 (June 4, 2010). In the proposed rule, EPA included provisions consistent with four of the Panel’s recommendations. As required by section 604 of the RFA, we also prepared a final regulatory flexibility analysis (FRFA) the final rule

. This final rule will not have 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 mentioned 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

- fir ed boilers are based on GACT, as opposed to the proposed MACT

- based 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 **172** of **298** 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 standa rds, as allowed under CAA section 112(h), instead of the MACT

- based 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 , onl y work practice standards or management practice, for 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 impact 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. The rule is intende d to reduce emissions of HAP as required under section 112 of the CAA. Section II.A of the final rule’s preamble describes the reasons that EPA is finalizing this action. Many significant issues were raised during the public comment period, and EPA’s res ponses to those comments are presented in section V of this preamble or 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 **173** of **298** response to comments document contained in the docket. Significant changes to the rule that resulted from the public
comments a re described in section IV of this preamble. The primary comments on the IRFA were provided by SBA, with the remainder of the comments generally supporting SBA’s comments. Those comments applicable to the proposal regarding area source boilers included the following: EPA should have adopted additional subcategories, including the following: unit design type (e.g. fluidized bed, stoker, fuel cell, suspension burner), duty cycle, geographic location, boiler size, burner type (with and without low

- NOx burners), and hours of use (limited use); EPA should h ave minimized facility monitoring and reporting requirements; EPA should not have proposed the energy audit requirement; and EPA’s proposed emissions standards are too stringent. In response to the comments on the IRFA and other public comments, EPA made t he following changes to the final rule. EPA is promulgating management practice standards requiring the implementation of a boiler tune

- up program for area source boilers in the biomass and oil subcategories instead of the proposed CO emission limits. Th is change will significantly reduce the monitoring and testing costs for existing and new**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 **298** biomass

- fired and oil

- fired area source boilers. EPA also decreased monitoring and testing costs for coal

- fired area source boilers by eliminating the CO CEMS requir ement for boilers greater than 100 MMBtu/h. The final rule also includes work practice standards or management practice standards, instead of emission limits, for new area source boilers less than 10 MMBtu/h. Finally, EPA is finalizing emission limits th at are less stringent than the proposed limits. The emission limit changes are largely due to the changes in data corrections and incorporation of new data into the floor calculations. Additional details on the changes discussed in this paragraph are inc luded in sections IV and V of the final rule’s preamble. EPA does not have sufficient information to estimate the number of small entities expected to be covered by the area source rule. As discussed in section 5.1 of th e RIA for this rule , using these cost data and the Census estimates of average establishment receipts, a substantial number of SUSB NAICS/enterprise categories have ratios over 3%. The following types of representative small area source public facilities would have cost

- to

- revenue ratios exceeding 1 percent but below 3 percent: other public facilities (ratio > 1.7 percent) and churches (ratio = 1.5 percent).**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 **298** The information collection activities in this ICR include initial and annual stack tests, fuel analyses, operating parameter monitor ing, continuous O 2 monitoring for all coal

- fired area source boilers greater than 10 MMBtu/h, certified energy assessments for area source facilities having a boiler greater than 10 MMBtu/h, biennial tune

- ups, preparation of a startup, shutdown, malfunctio n plan (SSMP), preparation of a site

specific monitoring plan and a site

- specific fuel monitoring plan, one

- time and periodic reports, and the maintenance of records. Based on 13 states’ inventories of boilers, there are an estimated 92,000 existing facil ities with affected boilers. It is estimated that 53 percent are located in the private sector and the remaining 47 percent are located in the public sector. Of these, only about 0.3 percent of the area source facilities are subject to emission limits an d the testing and monitoring requirements in the final rule. A table included in the FRFA summarizes the types and number of each type of small entities expected to be affected by the area source rule. The Agency expects that persons with knowledge of .pdf software, spreadsheet and relational database programs will be necessary in order to prepare the report or record. Based on experience with previous emission stack testing, we expect most**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 **298** facilities t o contract out preparation of the reports associated with emission stack testing, including creation of the Electronic Reporting Tool submittal which will minimize the need for in depth knowledge of databases or spreadsheet software at the source. We also expect affected sources will need to work with web

- based applicability tools and flowcharts to determine the requirements applicable to them, knowledge of the heat input capacity and fuel use of the combustion units at each facility will be necessary in o rder to develop the reports and determine initial applicability to the rule. Affected facilities will also need skills associated with vendor selection in order to identify service providers that can help them complete their compliance requirements, as ne cessary. While EPA did make significant changes based on public comment, EPA is maintaining, but clarifying, the energy assessment requirement. Some changes to the energy assessment requirement that will reduce costs for small entities include a the follo wing provisions: the energy assessment for facilities with affected boilers using less than 0.3 trillion Btu per year heat input will be one day in length maximum. The boiler system and energy use system accounting for at least 50 percent of the
energy o utput will be evaluated to identify energy savings**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 **298** opportunities, within the limit of performing a one

- day energy assessment; and the energy assessment for facilities with affected boilers using 0.3 to 1.0 trillion Btu per year will be 3 days in length max imum. The boiler system and any energy use system accounting for at least 33 percent of the energy output will be evaluated to identify energy savings opportunities, within the limit of performing a 3

- day energy assessment. In addition, the final rule al lows facilities to use a previously completed energy assessment to satisfy the energy assessment requirement. As required by section 212 of SBREFA, EPA also is preparing a Small Entity Compliance Guide to help small entities comply with this rule. Small e ntities will be able to obtain a copy of the Small Entity Compliance guide at the following web site: http://www.epa.gov/ttn/atw/boiler/boilerpg.html.
D. Unfunded Mandates Reform Act of 1995 Title II of the Unfunded Mandates Reform Act of 1995 (UMRA), P ublic Law 104

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

-**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 **298** benefit analysis, for proposed and final rules with

“ Federal federal mandates” that may result in expenditures to
State state , local, and tribal governments, in the aggregate, or to the private sector, of $100 million or more in any 1 year. Before promulgating a rule for which a written statement is needed, 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 appl icable 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 governments, including tribal governments, we must develop a small government agency plan under section 203 of the UMRA . The plan must provide for notifying po tentially affected small governments, enabling officials of affected small governments to have meaningful and timely input in the development of regulatory proposals with significant**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 **298** Federal 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 federal mandate that may result in expenditures of $100 million or more for State state , local, and Tribal 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. Statutor y 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, compoun ds, or groups of chemicals deemed by Congress to be HAP. These toxic air pollutants are to be regulated by NESHAP. 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 s ection 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**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 **298** public health in the largest number of urban areas. CAA section 112(c)(3) requires EPA to l ist sufficient categories or subcategories of area sources to ensure that area sources represent ing 90 percent of the emissions of the 30 urban HAP are subject to regulation. Under CAA section 112(d)(5), we may elect to promulgate standards or requirement s for area sources based on GACT used by those sources to reduce emissions of HAP. Determining what constitutes GACT involves 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, the control technologies and management practices at area and major sources in similar categories , to determine if the standards, te chnologies , and /or practices are transferable and generally available to area

sources. I n determining GACT for a particular area source category, we consider the costs and economic impacts of available control technologies and management practices on that category. While GACT may be a basis for standards for most types of HAP emitted from area source, CAA s ection 112(c)(6) requires**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 **298** 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 the listed categories be subject to MACT regulation. The CAA section 112(c)(6) list of source categories includes industrial boilers a nd 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 coa l

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

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

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

- fired and oil

- fired boilers under GACT. This NESHAP w ill apply to all existing and new industrial boilers, institutio nal 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**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 **298** alternatives. Additional information on the costs and environmental impacts of thes e regulatory alternatives is presented in the docket. The emission limits for existing area source boilers are only applicable 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 stan dards w ill require new coal

fired boilers to meet MACT

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

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

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

ups, and GACT

- based emission limits for PM. Existing large coal

- fired boilers w ill be required to meet 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 implementation of a tune

- up program is being established for existing and new 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 **183** of **298** boilers with a designed heat input capacity of l ess 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 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 regulatory 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 pre dicted change in prices and production in the affected industries, the estimated social costs of this final rule are $ [ 0.49 ] billion (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 HAP from area source boilers. Studies have determined a relationship between**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 **298** 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 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 health effect associated with reducing PM 2.5 and PM 2.5 precursors (such as SO 2 ) is a red uction 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 una ble 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. For 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**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 **298** 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 discuss ed in more detail in Section VII.D of this preamble. For more detailed information on the benefits estimated for the rulemaking, refer to the RIA in the docket. 3. Future and Disproportionate 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 budgetary effects. Our estimates of the future compliance costs of th is 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 the country, State 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 discussed in Section VII.C of this preamble. 4. Effects on the National Economy**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 **298** 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 int ernational competitiveness of the U.S. goods and services, if we determine that accurate estimates are reasonably feasible and that such effect is relevant and material. The nationwide economic impact of this 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 mentioned above. The results of the economic impact analysis are summarized in Section VII.C of this pream ble. 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 state , local, and tribal officials, summarize 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 **187** of **298** officials’ comments or concerns, and summarize our response to those comments or concerns. In addition, section 203 of the UMRA requires that we develop a plan for in forming and advising small governments that may be significantly or uniquely impacted by a proposal. Consistent with the intergovernmental consultation provisions of section 204 of the UMRA, EPA has initiated consultations with governmental entities affec ted by this rule

. EPA invited the following 10 national organizations representing State 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 Legislatu res, (3) Council of State Governments, (4) National League of Cities, (5) U.S. Conference of Mayors, (6) National Association of Counties, ( 7 ) International City/County Management Association, ( 8 ) National Association of Towns and Townships, (9) County
Exe cutives of America, and (10) E nvironmental C ouncil of S tates
. These 10 organizations of elected S tate s tate and local officials have been identified by EPA as the “Big 10” organizations appropriate to contact for purpose of consultation with elected officials. The purposes of the consultation were to provide general background on the proposal, answer questions, and solicit input from State s tate /local go vernments. During 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 **188** of **298** meeting, officials expressed uncertainty with regard to how boilers owned/operated by State state and local entities would be impacted, as well as with regard to the potential burden associated with implementing this final rule on State state and local entities. To that end, officials requested and EPA provided (1) m odel boiler costs , ( 2 ) i nventory of area source boilers (coal, oil, biomass only) fo r the 13 S tates s tates for which we have an inventory, and ( 3 ) i nformation on potential size of boilers used for various facility types and sizes. EPA has not received additional questions or requests from
State 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 p ractice standards and requiring an energy a ssessmen t. The regulatory alternative**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 **298** selected is a combination of the options considered and includes provisions regarding each of the SBAR Panel’s recommendations for area source boilers

. The recommendations r egard 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 appropriate because different types of units have differen t emission characteristics which may affect the feasibility and effectiveness of emission 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 other 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 alternative upon which the standards are based represents 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 **190** of **298** 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 surrogate 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 fac ilities 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 polluta nts w ill result in reduced compliance costs because testing is only be required for the 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 boilers. 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 t he requirements of section 203 of the UMRA because it contains no regulatory requirements that might significantly or uniquely affect small governments. While**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 **298** 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 to boilers owned and/or operated by governments and to boilers owned 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 f ederal government provides the funds necessary to pay the direct compliance costs incurred by
State s tate and local governments, or EPA consults with
State s tate 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 s tate or local governments, and 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 **192** of **298** Federal f ederal government will not provide the funds necessary to pay those costs. A ccordingly, 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 RIA for today’s action, the regulatory option may have federalism implications because the action may impose approximately $ 276 million in annual direct compliance costs on an estimated 57,000 State s tate or local governments. Boiler inventories for the health services, educational services, and government

- owned buildings sectors from 13 States were used to estimate the nationwide number of potentially impacted State s tate or local governments. Because the inventories for these sectors include privately owned and Federal f ederal government owned facilities, the estimate may include many facilities that are not State s tate or local government owned. Table 8 of this preamble presents estimates of the number of potentially impacted State s tate and local governments and their potential annual 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 (boi lers with 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 **193** of **298** 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. All facilities with large boilers w ill be required to conduct a one

- time energy assessment. **Table 8**  **. State and local governments potentially impacted by the standards for boilers at area source facilities** 
**Sector Number of potentially**  **impacted facilities Annual compliance**  **costs to meet standards**  Total Small Large **Health Services**  1 7,206 15,293 1,913 $ 84 m illion **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 s tate 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 state and local elected officials to provide general background on the propos ed rule , answer questions, and solicit input from State state /local governments. The UMRA discussion in Section IX.D this preamble Formatted: Font: Bold

Formatted: Font: Bold

Formatted Table Formatted: Left

Formatted: Font: Bold Formatted: Left Formatted: Font: Bold Formatted: Left Formatted: Font: Bold Formatted: Left**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 **298** 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 Order’s requirements in a meaningful and timely manner, when it sent the draft of this final action to
OM B for review pursuant to Executive Order 12866. A copy of this certification has been included in the public version of the official record for this final 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 requirements on owners and operators of specified area sources and not tribal governments. We do not know of any i ndustrial , commercial , or institutional boilers owned or operated by Indian tribal governments. However, if there are any, the effect of this final rule on communities of tribal governments would not be unique or disproportionate to the effect on other co mmunities. Thus, Executive Order 13175 d oes not apply to th is action

. G
. Executive Order 13045: Protection of Children from Environmental Health Risks and Safety Risks**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 **298** Th is action is not subject to Executive Order 13045 because the Agency does not bel ieve the environmental health risks or safety risks addressed by this action present a disproportionate risk to children. In addition, this action is not subject to Executive Order 13045 because this final rule is based solely on technology performance.
H
. Executive Order 13211: Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution, or Use Th is action is not a “significant 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 price, 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 National 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 applicable law or otherwise**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 **298** impractical. The VCS are technical standards (e.g., mat erials specifications, test methods, sampling procedures, and business practices) that are developed or adopted by VCS bodies. The NTTAA directs EPA to provide Congress, through OMB, explanations when the Agency does not use available and applicable VCS. This final rule inv olves technical standards. EPA cites 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 40 CFR part 60; 101A of 40 CFR part 61; and voluntary consensus standards: Ameri can 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 D6323

- 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 applicable 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 standards. EPA determined that these 16 standards identified for measuring emissions of the 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 **197** of **298** 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 determinati on 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 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 permiss ion to use alternative test methods or alternative monitoring requirements in place of any required testing methods, performance specifications, or procedures.
J. Executive Order 12898: Federal Actions to Address Environmental Justice in Minority Populat ions and Low

- Income Populations Executive Order 12898 (59 FR 7629, February 16, 1994) establishes Federal f ederal executive policy on environmental justice ( EJ ). Its main provision directs Federal 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 ac tivities on minority populations, low

- income,**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 **298** and Tribal t ribal populations in the United States. This action establishes national emission standards for industrial, commercial, and institutional boilers that are area sources. The industrial boiler source category includes boilers used in manufacturing, processing, mining, refining, or any other industry. The commercial boiler source category includes boilers used in commercial establishments such as stores/malls, laundries, apartments, restaurants, theat res, 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 build ings (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 resid ential 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 distributi ons of exposures and health risks attributable to these sources among different socio

-**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 **298** 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 an ticipated 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 rule will also result in reductions in criteria pollutants 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 implementati on of this rule is anticipated to have health benefits 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 emission s 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 t hat 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**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 **298** because it increases the level of environmental protection for all af fected populations without having any disproportionately high and adverse human health or environmental effects on any population, including any minority, low

- income, or Tribal t ribal populations. EPA defines “Environmental Justice” to include meaningful involvement of all people regardless of race, color, national origin, or income with respect to the development, implementation, and enforcement of environmental laws, regulations, and polices. To promote meaningful involvement, EPA has developed a n EJ co mmunication strategy to ensure that interested communities have access to this rule, are aware of its content, and have an opportunity to comment

. In addition,
S tate s tate and F ederal f ederal permitting requirements will provide S tate s tate and local governments and communities the opportunity to provide their comments on the permit 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 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 **201** of **298** report, which includes a copy of this final rule , to each House of the Congress and to the Compt roller 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 ru le in the Federal Register

. A m ajor rule cannot take effect until 60 days after it is published in the Federal Register

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

. Formatted: Underline**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 **298** List of Subjects in 40 CFR part 63 Environmental protection, Administrative practice and procedure, Air pollution control, Hazardous substances, Intergovernmental relations, Incorporat ion 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 **203** of **298**
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 e t seq . **Subpart A —**  **[AMENDED]**

2. Section 63.14 is amended by revising :

a. Revising paragraphs (b) (27), (b)( 35), (b)( 39 ) through (44 ), (b)(47 ), (b)(49), (b)(50), (b)( ) through ( 5 2 ), (b)( 55), (b)(56), (b)(58 57 ), (b)(61), (b) ( 62 64 ) , and (i)(1 ) to read as follows: ). b. Removing and reserving paragraphs (b)(45), (b)(46), (b)(55), (b)(56), (b)(58) through (60), and (b)(62). c. Adding paragraphs (b)(66) through (68). d. Adding paragraphs (o) and (p). §63.14 Incorporation by reference.

* * * * * (b) * * * (27) ASTM D6522

– 00, Standard Test Method for Determination of Nitrogen Oxides, Carbon Monoxide, and Oxygen Formatted: ___GHG PARAGRAPH, Line spacing: single

Formatted: Font: 10 pt
Formatted: ___GHG PARAGRAPH, Line spacing: single**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 **298** Concentrations in Emissions from Natural Gas Fired Reciprocating Engines, Combustion Turbines, Boilers, and Process Heaters Using Portable Analyzer s, IBR approved for §63.9307(c)(2)

.

* * * * * (35) ASTM D6784

- 02 (Reapproved 2008) Standard Test Method for Elemental, Oxidized, Particle

- Bound and Total Mercury in Flue Gas Generated from Coal

- Fired Stationary Sources (Ontario Hydro Method) , approved April 1, 2008 , IBR approved for t able 1 to subpart DDDDD of this part, t able 2 to subpart DDDDD of this part, t able 5 to s ubpart DDDDD , table 12 to subpart DDDDD of this part, and table 4 to subpart JJJJJJ of this part

.

* * * * * (39) ASTM Method D388

- 05 , Standard Classification of Coals by Rank 1 Rank, approved September 15, 2005 , IBR approved for §63.7575 and §63.11237.

* * * * * (40) ASTM D396

- 10 Standard Specification for Fuel Oils , approved October 1, 2010, IBR approved for §63.7575. (41) ASTM Method D1835

– 05, Standard Specification for Liqu e fied Petroleum (LP) Gases, 1 approved April 1, 2005 , IBR approved for §63.7575 and §63.11237

.

* * * * * Formatted: ___GHG PARAGRAPH, Line spacing: single

Formatted: ___GHG PARAGRAPH, Indent: First line: 0", Line spacing: single**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 **298** (58 (42) ASTM D2013/D2013M

- 09 Standard Practice for Preparing Coal Samples for Analysis, approved November 1, 2009 , IBR approved for table 6 to subpart DDDDD of this part and table 5 to subpart JJJJJJ of this part. (43) ASTM D2234/D2234M

- 10 Standard Practice for Collection of a Gross Sample of Coal, approved January 1, 2010 , IBR approved for table 6 to subpart DDDDD of this part and table 5 to subpart JJJJJJ of this part. (44 ) ASTM D3173

– 03 ( Reapproved 2008 ) , ) Standard Test Method for Moisture in the Analysis Sample of Coal and Coke, approved February 1, 2008 , IBR approved for Table table 6 to subpart DDDDD of this part and Table table 5 to subpart JJJJJJ of this part.

* * * * * (47) ASTM D5198

- 09 Standard Practice for Nitric Acid Digestion of Solid Waste, approved February 1, 2009 , IBR approved for table 6 to subpart DDDDD of this part and table 5
to subpart JJJJJJ of this part. (48) ASTM D5865

– 10a Standard Test Method for Gross Calorific Value of Coal and Coke, approved May 1, 2010 , IBR approved for table 6 to subpart DDDDD of this part and table 5 to subpart JJJJJJ of this part. Formatted: ___GHG PARAGRAPH, Line spacing: single

Formatted: __STARS, Indent: Left: 0", First line: 0", Line spacing: single, Tab stops: Not at 0.5" + 1" + 1.5" + 2" + 2.5"**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 **206** of **298** (49) ASTM D6323

– 98 (Reapproved 2003), Standard Guide for Laboratory Subsampling of Media Related to Waste Management Activities, approved August 10, 2003 , IBR approved for table 6 to subpart DDDDD of this part and table 5 to subpart JJJJJJ of this part. (50) ASTM E711

- 87 (Reapproved 2004) Standard Test Method for Gross Calorific Value of Refuse

- Derived Fuel by the Bomb Calorimeter, approved August 28, 1987 , IBR approved for table 6 to subpart DDDDD of this part and table 5 to subpart JJJJJJ of this part. (51) ASTM E776

- 87 (Reapproved 2009) Standard Test Method for Forms of Chlorine in Refuse

- Derived Fuel, approved July 1, 2009 , IBR approved for table 6 to subpart DDDDD of this part. (52) ASTM E871

- 82 (Reapproved 2006) Standard Test Method for Moisture Analysis of Particulate Wood Fuels, approved November 1, 200 6 , IBR approved for table 6 to subpart DDDDD of this part and table 5 to subpart JJJJJJ of this part.

* * * * * (57) ASTM D6 721

- 01 (Reapproved 2006) Standard Test Method for Determination of Chlorine in Coal by Oxidative Hydrolysis Microcoulometry, approved April 1, 2006 , IBR approved for table 6 to subpart DDDDD of this part.**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 **298**

* * * * * (61) ASTM D6722

– 01 (2006 ) , ) Standard Tes t Method for Total Mercury in Coal and Coal Combustion Residues by the Direct Combustion Analysis, approved April 1, 2006 , IBR approved for Table 6 to subpart DDDDD and Table 5 to subpart JJJJJJ of this part. (62 * * * * * (64 ) ASTM D5865

– 10a , D6522

– 00 (Reapproved 2005), Standard Test Method for Gross Calorific Value Determination of Coal Nitrogen Oxides, Carbon Monoxide, and Coke Oxygen Concentrations in Emissions from Natural Gas Fired Reciprocating Engines, Combustion Turbines, Boilers, and Process Heate rs Using Portable Analyzers, approved October 1, 2005 , IBR approved for Table 6 table 4 to subpart DDDDD and Table ZZZZ of this part, table 5 to subpart DDDDD of this part, and table 4 to subpart JJJJJJ of this part.

* * * * * * * * (66) ASTM D4084

– 07 Standard Test Method for Analysis of Hydrogen Sulfide in Gaseous Fuels (Lead Acetate Reaction Rate Method), approved June 1, 2007, IBR approved for table 6 to subpart DDDDD of this part. Formatted: ___GHG PARAGRAPH, Line spacing: single

Formatted: ___GHG PARAGRAPH, Line spacing: single**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 **298** (67) ASTM D5954

- 98 (Reapproved 2006), Test Method for Mercury Sampl ing and Measurement in Natural Gas by Atomic Absorption Spectroscopy, approved December 1, 2006, IBR approved for table 6 to subpart DDDDD of this part. (68) ASTM D6350

- 98 (Reapproved 2003) Standard Test Method for Mercury Sampling and Analysis in Natural Gas by Atomic Fluorescence Spectroscopy, approved May 10, 2003, IBR approved for table 6 to subpart DDDDD of this part. ( i ) * * * (1) ANSI/ASME PTC 19.10

– 1981, “Flue and Exhaust Gas Analyses [Part 10, Instruments and Apparatus],” IBR approved for §§63.309(k)(1)(iii), 63.865(b), 63.3166(a)(3), 63.3360(e)(1)(iii), 63.3545(a)(3), 63.3555(a)(3), 63.4166(a)(3), 63.4362(a)(3), 63.4766(a)(3), 63.4965(a)(3), 63.5160(d)(1)(iii), 63.9307(c)(2), 63.9323(a)(3), 63.11148(e)(3)(iii), 63.11155(e)(3), 63.11162(f)( 3)(iii) and (f)(4), 63.11163(g)(1)(iii) and (g)(2), 63.11410(j)(1)(iii), 63.11551(a)(2)(i)(C), table 5 to subpart DDDDD of this part, table 1 to subpart ZZZZZ of this part , and table 4 to subpart JJJJJJ of this part.

* * * * ***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 **298** (o) The following material i s available from the U.S. Environmental Protection Agency, 1200 Pennsylvania Avenue, NW., Washington, DC 20460, (202) 272

– 0167, http://www.epa.gov. (1) National Emission Standards for Hazardous Air Pollutants (NESHAP) for Integrated Iron and Steel Plants

— Background Information for Proposed Standards, Final Report,

EPA

– 453/R

– 01

– 005, January 2001, IBR approved for §63.7491(g). (2) Office Of Air Quality Planning And Standards (OAQPS), Fabric Filter Bag Leak Detection Guidance, EPA

– 454/R

– 98

– 015, September 19 97, IBR approved for §63.7525(j)(2) and §63.11224(f)(2)

. (3) SW

– 846

– 3020A, Acid Digestion of Aqueous Samples And Extracts For Total Metals For Analysis By GFAA Spectroscopy, Revision 1, July 1992, in EPA Publication No. SW

– 846, Test Methods for Evaluating Solid Waste, Physical/Chemical Methods, Third Edition, IBR approved for table 6 to subpart DDDDD of this part and table 5 to subpart JJJJJJ of this part. (4) SW

– 846

– 3050B, Acid Digestion of Sediments, Sludges, And Soils, Revision 2, December 1996, in EPA Publication No. SW

– 846, Test Methods for Evaluating Solid Waste, Physical/Chemical Methods, Third Edition, IBR approved for table 6 to subpart DDDDD of this part and table 5 to subpart JJJJJJ of this part.**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 **298** (5) SW

- 846

- 7470A, Mercury In Liquid Waste (Manu al Cold

Vapor Technique), Revision 1, September 1994, in EPA Publication
No. SW

– 846, Test Methods for Evaluating Solid Waste, Physical/Chemical Methods, Third Edition, IBR approved for table 6 to subpart DDDDD of this part and table 5 to subpart JJJJJJ of this part. (6) SW

- 846

- 7471B, Mercury In Solid Or Semisolid Waste (Manual Cold

- Vapor Technique), Revision 2, February 2007, in EPA Publication No. SW

– 846, Test Methods for Evaluating Solid Waste, Physical/Chemical Methods, Third Edition, IBR approved for t able 6 to subpart DDDDD of this part and table 5 to subpart JJJJJJ of this part. (7) SW

- 846

- 9250, Chloride (Colorimetric, Automated Ferricyanide AAI), Revision 0, September 1986, in EPA Publication No. SW

– 846, Test Methods for Evaluating Solid Waste, Phys ical/Chemical Methods, Third Edition, IBR approved for table 6 to subpart DDDDD of this part. (p) The following material is available for purchase from the International Standards Organization (ISO), 1, ch. de la Voie

- Creuse, Case postale 56, CH

– 1211 Gene va 20, Switzerland, +41 22 749 01 11, http://www.iso.org/iso/home.htm.**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 **298** (1) ISO 6978

- 1:2003(E), Natural Gas

– Determination of Mercury

- Part 1: Sampling of Mercury by Chemisorption on Iodine, First edition, October 15, 2003 , IBR approved for table 6 to su bpart DDDDD of this part. (2) ISO 6978

- 2:2003(E), Natural gas

- Determination of Mercury

- Part 2: Sampling of Mercury by Amalgamation on Gold/Platinum Alloy, First edition, October 15, 2003 , IBR approved for table 6 to subpart DDDDD of this part. 3
. Part 63 is amended by adding subpart JJJJJJ to read as follows: **Subpart JJJJJJ --**  **National Emission Standards 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 Manag**  **ement Practices** 63.11200 What are the subcategories of boilers? 63.11201 What standards must I meet? **Initial General**  **Compliance Requirements**
63.11205 What are my general requirements for complying with this subpart? **Initial Compliance Requirements 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 **298**

63. 11210 What are my initial compliance requirements and by what date must I conduct them? 63.11211 How do I demonstrate initial compliance with 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 m ust 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 w ith the work practice standards and management practices ? 63.11224 What are my monitoring, installation, operation, and maintenance requirements? 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 General 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 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

— Establishing Operating Limit**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 **298** Table 7 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 to 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 hazardous 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 , reconstructed, 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 , (coal, biomass, oil ), as listed in §63.11200 and defined in §63.11237, located at an area source. (2) The affected sourc e of this subpart is each new or reconstructed industrial, commercial, or institutional boiler Formatted: ___GHG PARAGRAPH, Line spacing: single, Tab stops: Not at 0" + 0.5" + 1" + 1.5" + 2" + 2.5" + 3" + 3.5" + 4" + 4.5" + 5" + 5.5" + 6" + 6.5"**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 **214** of **298** within a subcategory, as listed in §63.11200 and as defined in §63.11237, located at an area source. (b) An affecte d 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 affected source after June 4, 2 010 and you meet the applicability criteria at the time you commence construction

. (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 e xempt 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 sentence, you must continue to co mply with the provisions 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 **215** of **298** §63.11195 Are any boilers not subject to this subpart ? The types of boilers listed in paragraphs (a) through ( e g ) of this section are not subject to this subpart and to any requirements in 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 sectio n 129 of the Clean Ai r 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 boiler s 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 r esearch and development, however, the boiler must be concurrently and primarily engaged in research and development for the exemption to apply. (e) A gas

- fired boiler as defined in 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 **216** of **298** (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 co mpliance dates? (a) If you own or operate an existing affected

source boiler , you must achieve compliance with the applicable provisions in this subpart as specified in paragraphs (a)(1)
t hrough ( a)( 3) of this section. (1) If the existing affected boiler is subject to a work practice or management practice standard of a tune

- up, you must achieve compliance with the work practice or management standard no later than [INSERT THE DATE 1 YEAR S YEAR AFTER PUBLICATION OF
THIS FINAL RULE IN THE FEDERAL REGISTER]. (2) If the existing affected boiler is subject to emission limits, you must achieve compliance with the emission limits no later than [INSERT THE DATE 3 YEARS AFTER PUBLICATION OF THIS
FINAL RULE IN THE FEDERAL REGISTER]. (3) If the existing affected boiler is subject to the energy assessment requirement, you must achieve compliance with the energy assessment requirement no later than [INSERT THE DATE**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 **298** 3 YEARS AFTER PUBLICATION OF THIS FINAL RULE 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 OF THIS
FINAL RULE IN THE FEDERAL REGISTER], you must achieve compliance with the provisions of this subpar t no later than [INSERT THE

DATE 60 DAYS AFTER THE DATE OF PUBLICATION OF THIS FINAL RULE IN THE FEDERAL REGISTER]. (c) If you start up a new affected source after [INSERT
THE DATE 60 DAYS AFTER THE DATE OF PUBLICATION OF THIS FINAL
RULE IN THE FEDERAL R EGISTER], 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 s ubpart DDDD, and you cease combusting solid waste, you must be in compliance with this subpart on the effective date of the waste to fuel switch , if the effective date of that switch is after the applicable compliance date in paragraphs (a)

- (c) of this sec tion . The effective date of 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 **218** of **298** waste to fuel switch is a date selected by you consistent with part 60, subpart CCCC or subpart DDDD that must 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 oil . Each subcategory is defined in §63.11237. §63.11201 What standards must I meet ? (a) You must comply with each emi ssion limit specified in Table 1 of to 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 to 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 to this subpart satisf ies the energy assessmen t portion of this requirement. (c) You must comply with each operating limit specified in Tabl e 3 of to 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 with Formatted: Centered**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 **298** this subpart? (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 genera l 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 used will be based on in formation available to the Administrator which that 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) You 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 testing. ( c ) If you dem onstrate compliance with any ap plicable emission limit through performance stack testing and subsequent compliance with operating limits (including the use 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 **220** of **298** continuous parameter monitoring system ) , or with a CEMS, or COMS, you must develop a site

- specific monitoring plan according to the require ments in paragraphs ( c )(1) through (4) of this section for the use of any CEMS, COMS, or continuous parameter monitoring system

. This requirement also applies to you if you petition the EPA Administrator for alternative monitoring parameters under §63.8(f ). (1) For each CMS required in this section (including CEMS, COMS, or continuous parameter monitoring system) , you must develop , and submit to the delegated authority for approval upon request, a site

- specific monitoring plan that addresses paragraphs ( c )(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 your
CMS. Th is requirement to develop and submit a site specific monitoring plan does not apply to affected sources with existing monitoring plans that apply to CEMS and COMS prepared under Appendix B to part 60 of this chapter and which meet the requirements of § 63. 1 1224
. (i) Installation of the CMS sampling probe or other interface at a measureme nt location relative to each affected process unit such that the measurement is representative 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 **221** of **298** control of the exhaust emissions (e.g., on or downstream of the last contro l device); (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 criter ia ( e.g., calibrations). (2) In your site

- specific monitoring plan, you must also address paragraphs ( c )(2)(i) through (iii) of this section. (i) Ongoing operation and maintenance procedures in accordance with the general requirements of §63.8(c)(1) (ii), (c)(3), and (c)(4)(ii); (ii) Ongoing data quality assurance procedures in accorda nce 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) (as applica ble in Table 10 to this subpart), (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.**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 **298 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 emission limit specified in Table 1 of to thi s subpart that applies to you by either conducting performance (stack) tests, as applicable, according to §63.11212 and Table 4 of to this subpart or, for mercury, conducting fuel analyses, as applicable, according to §63.11213 and Table 5 to this subpart. (b) For existing affected sources boiler s 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 boiler s 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**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 **298** after [INSERT THE DATE OF PUBLICATION OF THIS FINAL RULE IN THE
FEDERAL REGISTER] or within 180 calendar days after startup of the source, whichever is later, according to §63.7(a)(2)(ix). (e ) For affected sources boiler s that ceased burning solid waste consistent with §63. 11196(d), you must demonstrate compliance within 60 da ys of the effective date of the waste

- to

- fuel switch. You If you have not conducted your compliance demonstration for this subpart within the previous 12 months,

y ou must complete all initial compliance demonstrations before
you commence or recomm ence combustion of solid waste. §63.11211 How do I demonstrate initial compliance with the emission limits? (a) For affected sources boiler s that demonstrate compliance with any of the emission limits of this subpart through performance (stack) testing, your initial compliance requirements include conducting performance tests according to §63.11212 and Table 4 to this subpart , conductin g 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 , Table 6 to this subpart and paragraph (b) of this section, as applicable , and conducting continuous monitoring system ( CMS ) performance evaluations**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 **298** 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 purposes 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 analysis requirements under §63. 11213 and Table 5 to this subpart

. (b ( b ) You must establish parameter operating limits according to paragraphs ( b)( 1 ) through ( 4 ) of this section. ( 1 ) For a wet scrubber, you must establish the minimum liquid flowrate and pressure drop as defined in §63. 11237 , as your operating limits during the three

- run performance stack test. If you use a wet scrubber and you conduct separate performance stack tests for particulate matter and mercury emissio ns, you must establish one set of minimum scrubber liquid flowrate and pressure drop operating limits. If you conduct multiple performance stack tests, you must set the minimum liquid flowrate and pressure drop operating limits at the highest minimum valu es established during the performance stack
tests. Formatted: Font: Courier New**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 **298** ( 2 ) For an electrostatic precipitator operated with a wet scrubber, you must establish the minimum voltage and secondary amperage (or total power input), as defined in §63. 11237 , as your operating limits during the three

- run performance stack test. (These operating limits do not apply to electrostatic precipitators that are operated as dry controls without a wet scrubber.) ( 3 ) For activated carbon injection, you must establish the minimum activated carbo n injection rate, as defined in §63. 11237 , as your operating limit during the three

- run performan ce stack test. ( 4 ) The operating limit for boilers with fabric filters that demonstrate continuous compliance through bag leak detection systems is that a bag leak detection system be installed according to the requirements in §63. 11224 , and that each fabric filter must be operated such that the bag leak detection system alarm does not sound more than 5 percent of the operating time during a 6

- month period. ( c ) 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 to this subpart and follow the procedures in paragraphs ( b c )(1)**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 **298** through (3) of this section. (1) If you burn more than one fuel type, you must determine the fuel type , or mixture, you could burn in your boiler that would result in the maximum emission rates of
mercury. (2) You must determine the 90th percenti le confidence 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 compliance with the applicable mercury 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.**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 **298** §63.11212 What stack tests and procedures mu st I use for the 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 t o the requirements 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 representative operating load conditions 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 and establish your operating limits b ased on these performance stack tests. For subcateg ories with more than one emission limit, these requirements could result in the need to conduct 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 for each performance stack 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 Formatted: Font: Courier New**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 **298** test runs conducted for mercury emissions 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

- 7 to part 60 of this chapter to convert the measured PM particulate matter concentrations and the measured mercury concentrations that result from the initial performance test to pounds per million Btu heat input e mission rates. §63.11213 What fuel analyses and procedures must I use for the performance tests ? (a) You must conduct 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

. You are required to conduct fuel analyses only for fuels and units that are subject to emission limits for mercury in Table 1 of this subpart. (b) At a minimum, you must obtain three composite fuel samples for each fuel type according to the procedures in Table
5 of to this subpart. Each composite sample will must 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 **229** of **298** intervals 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 initial 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 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 boiler. (b) If you own or operate a n existing or new biomass

- fired boiler or a n existing or new liquid fuel oil

- 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 boiler. (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 **230** of **298** must submit the energy assessment report, al ong with a signed certification that the assessment is an accurate depiction of your facility. (d) If you own or operate a boiler subject to emission limits in Table 1 of this subpart, you must minimize the boiler’s startup and shutdown periods following the manufacturer’s recommended procedures, if available. If manufacturer’s recommended procedures are not available, you must follow recommended procedures for a unit of similar design for which manufacturer’s recommended procedures are available.
You mus t 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 or procedures specified for a boiler of similar design if manufactur er’s recommended procedures are not available. **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 hou r or greater, you must conduct all applicable performance (stack) tests according to §63.11212 on an annual basis, unless you follow the requirements listed in paragraphs**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 **298** (b) through (d) of this section. Annual performance tests must be completed between 1 1 and no more than 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 equip ment 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 and no more than 3 7 months after the previous p erformance 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 em ission limit, and if there are no changes in the operation of the affected source or air pollution control equipment that could increase emissions, but each such performance stack test must 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 **232** of **298** conducted no more than 36 3 7 months after the previous performan ce test
. (d) If a performance stack test shows emissions exceeded 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 applicable 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 no more than 1 3 months after the previous performance test. (f) If you demonstrate compliance with the mercury emission limit based on fuel analysis, you must conduct a fuel 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
ap plicable emission limit. §63.11221 How do I monitor and collect data to demonstrate continuous 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 **233** of **298** ( a ) You must monitor and collect data according to this section. ( b ) You must operate the monitoring system and collect data at 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, calibratio n checks and required zero and span adjustments. A monitoring system malfunction is any sudden, infrequent, not reasonably preventable failure of the monitoring system to provide valid data. Monitoring system failures that are caused in part by poor main tenance or careless operation are not malfunctions. You are required to effect monitoring system repairs in response to monitoring system malfunctions or out

- of

control periods and to return the monitoring system to operation as expeditiously as practicab le. ( c ) You may not use data recorded during monitoring system malfunctions or out

- of

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

- of

- control periods, or required monitoring system quality assurance or control Formatted: Indent: First line: 0.5"**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 **234** of **298** activitie s 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 malfu nctions
or out

- of

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

- of

- control periods, and required monitoring system quality assurance or quality control activities including, as applicable, calibration checks and required ze ro and span adjustments, failure to collect required data is a deviation of the monitoring requirements. §63.11222 How do I demonstrate continuous compliance with the emission limits? (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 4 ) 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**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 **298** Table 3 to this subpart. Operation above the established maximum or below the established minimum operating limits shall constitute constitute s 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 keep 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 emission s of mercury than the applicable emission limit

. (if you demonstrate compliance through fuel analysis) , or result in lower fuel input of mercury than the maximum values calculated during the last performance stack test (if you demonstrate compliance throug h performance stack testing)

. (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 per million Btu, using the procedures in Equ ation 1 of §63.11211 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.**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 **298** (ii) If the mercury concentration is higher than mercury fuel input during the previous performance test, then you must conduct a new performance test within 60 days of burning the new fuel type or fuel mixture according to the procedures in §63.11212 to demonstrate t hat 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 filter 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 ti me corrective action was initiated and completed, and a brief description of the cause of the alarm and the corrective action taken. You must also record the percent of the operating time during each 6

- month period that the alarm sounds. In calculating t his operating time percentage, if inspection of the fabric filter demonstrates that no corrective action is required, no alarm time is counted. If corrective action is required, each alarm shall be is counted as a minimum of 1 hour. If you take longer tha n 1 hour to initiate**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 **298** corrective action, the alarm time shall be is counted 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 an d 3 to this subpart that apply to you. These instances are deviations from the emission limits in this subpart. These deviations must be reported according to the requirements in §63.1122 5
. §63.11223 How do I demonstrate continuous compliance with the

w ork practice and management practice standards? (a) For affected sources subject to the work practice standard or the management practi ces of a tune

- up , you must conduct a biennial performance tune

- up according to §63. 11223(b) paragraphs (b) of this section and keep records as required in §63.1122 5 (c) to demonstrate continuous compliance. Each biennial tune

- up must be conducted between 23 and no more than 25 months after the previous tune

- up . (b) You must conduct a tune

- up of the boiler biennially to demonstrate continuous compliance as specified in paragraphs (b)(1) through ( 6 7 ) of this section. (1) Inspect As applicable, inspect the burner, and clean or replace any components of the burner as necessary ; (you may**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 **298** delay the burner inspection until the next scheduled unit shutdown, but you must inspect each burner at least once every 36 months)

. (2) Inspect the flame pattern , as applicable, and make any adjustments to adjust the burner as necessary to optimize the flame pattern . The adjustment should be consistent with the manufacturer’s specifications ; , if available

. (3) Inspect the system controlling the air

- to

- fue l ratio, as applicable, and ensure that it is correctly calibrated and functioning properly ; . (4) Optimize total emissions of CO carbon monoxide. This optimization should be consistent with the manufacturer’s specifications ; , if available

. (5) Measure the concentration concentrations in the effluent stream of CO carbon monoxide in parts per million, by volume, and oxygen in volume percent, before and after the adjustments are made (measurements may be either on a dry or wet basis (ppmvd), , as long as it is the same basis before and after the adjustments are made ; and )
. (6) Maintain on - site onsite and submit, if requested by the Administrator, a biennial report containing the information in paragraphs (b)(6)(i) through (iii) 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 **239** of **298** (i) The concentrations of CO in the effluent stream in ppmvd parts per million, by volume , and oxygen in volume percent dry basis , measured before and after the tune

- up of the boiler as defined in §63.11222(b) of this section ; . (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 sect ion

. (7) If the unit is not operating on the required date for
a tune

- up, the tune

- up must be conducted within one week of startup. ( 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 boiler’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**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 **298** maintenance requirements? (a (a) If your boiler is subject to a carbon monoxide emission limit in Table 1 o 2 to this subpart , you mu st install, operate, and maintain a continuous oxygen monitor according to the procedures in paragraphs (a)(1) through (6) of this se ction by the compliance date specified in §63. 11196
. The oxygen level shall be monitored at the outlet of the boiler. (1) Each monitor must be installed, operated, and maintained according to the applicable procedures under Performance Specification 3 at 40 CFR part 60, appendix B, and according to the site

- specific monitoring plan developed according to paragraph (c) of this section

. (2) You must conduct a performance evaluation of each CEMS according to the requirements in §63.8 (e) and according to
Per formance Specification 3 at 40 CFR part 60, appendix B. (3) Each CEMS must complete a minimum of one cycle of operation (sa mpling, analyzing, and data recording) for each successive 15

- minute period. (4) The CEMS data must be reduced as specified in §63.8(g)(2). (5) You must calculate and record a 30

- day rolling average concentration on a daily basis. A new 30

- day rolling average**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 **298** concentration is calculated as the average of all of the hourly oxygen concentration data for the preceding 30 operating days. (6) For purposes of calculating data averages, you must use all the data collected during all periods in assessing compliance, excluding data collected during periods when the monitoring system malfunctions or is out of control, during associated re pairs, and during required quality assurance or control activities (including, as applicable, calibration checks and required zero and span adjustments). Monitoring failures that are caused in part by poor maintenance or careless operation are not malfunc tions. Any period for which the monitoring system malfunctions or is out of control and data are not available for a required calculation constitutes a deviation from the monitoring requirements. Periods when data are unavailable because of required qual ity assurance or control activities (including, as applicable, calibration checks and required zero and span adjustments) do not constitute monitoring deviations. ( b ) If you are using a control device to comply with the emission limits specified in Table 1 of to this subpart, you must maintain each operating limit in Table 3 of to this subpart that applies to your boiler. If you use a control device not covered**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 **298** in Tab le 3 to this subpart , or you wish to establish and monitor an alternative operating limit and alternative monitoring parameters, you must apply to the United States Environmental Protection Agency (EPA) Administrator for approval of alternative monitoring under §63.8(f). ( b c ) If you demonstrate 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 c ) (1) through (4) of this section. This requirement 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 yo ur initial performance evaluation of your 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**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 **298** the exhaust emissions (e.g., o n or downstream of the last control device ); )
. (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 eval uation 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. (3) You must conduct a performance evaluation of each CMS in accordance with your site

- spec ific monitoring plan. Formatted: Font: 10 pt**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 **298** (4) You must operate and maintain the CMS in continuous operation according to the site

- specific monitoring plan. ( c d ) If you have an operating limit that requires the use of a CMS, you must install, operate, and maintain each

con tinuous parameter monitoring system (CPMS) according to the procedures in paragraphs ( c d )(1) through (5) of this section. (1) The CPMS continuous parameter monitoring system must complete a minimum of one cycle of operation for each successive 15

- minute p eriod. 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 control activities (including, as applicable, calibration c hecks 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 pro vide 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 recorded during monitoring malfunctions, associated repairs , out of control periods, or required quality assurance**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 **298** or control activities. You must use all the data collected during all other periods in assessing compliance. Any period for which the monitoring system is out

- of

- control and data are not available f or a required calculation constitutes a deviation from the monitoring requirements. (4) Determine the 4

- hour block average of all recorded readings, except as provided in paragraph ( c d )(3) of this section. (5) Record the results of each inspection, cal ibration, and validation check. ( d e ) 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 e )(1) thr ough (7) of this section by the compliance date specified in §63.11196. (1) Each COMS must be installed, operated, and maintained according to PS Performance Specification 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 Performance Specification 1 of 40 CFR part 60, appendix B. (3) As specified in §63.8(c)(4)(i), each COMS 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 **246** of **298** complete a minimum of one cycle of sampling and analyzing for each successi ve 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). (5) You must include in your site

- specific monitoring plan procedures and acceptance criteria for ope rating 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 must 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 qu arterly 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 f ) If you use a fabric filter bag leak detection system to comply with the requirements of this subpart, 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 **247** of **298** install, calibrate, maintain, and continuously operate the bag leak detection system as specified in paragraphs ( e f )(1) through (8) of this secti on. (1) You must install and operate a bag leak detection system for each exhaust stack of the fabric filter. (2) Each bag leak detection system must be installed, operated, calibrated, and maintained in a manner consistent with the manufacturer's writte n 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 de tection system must be equipped with a device to continuously 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**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 **298** preset level is detected. 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 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, repo rting, and recordkeeping, requirements ? (a) You must submit the notifications specified in paragraphs (a)(1) through (a)( 5 ) of this section to the delegated authority

. (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 OF THIS
FINAL RULE IN THE FEDERAL REGISTER ] or within 120 days after the source becomes subject to the standard.**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 **298** (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 in accordance with §63.9(h) no later than 120 days after the applicable compliance date spe cified 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 informat ion required in §63.9(h)(2), your notification must include the following certification(s) of compliance, as applicable, 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 For an 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**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 **298** detection system according 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 Ai r Act: “No secondary materials that are solid waste were combusted in any affected unit.” ( 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 initi al performance test results with the Notification of Compliance Status required under paragraph (a)( 4 ) of this section. (b) You must prepare, by March 1 of each year , and submit to the delegated authority upon request , an annual compliance certification report for the previous calendar year containing the information specified in paragraphs (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 3 ) of this section. For boiler s that are subject only to a requirement to conduct a biennial tune

- up according to §63. 11223 (a) and not subject to emission limits or operating limits, you may prepare only a biennial compliance report 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 **251** of **298**
spe cified in paragraphs (b)(1) through ( 4 ) of this section, instead of a semi

- annual compliance report

. (1) Company name and address. (2) Statement by a responsible official, with the official’s name, title, phone number, e

- mail address, and signature, cer tifying 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 source is not in compliance experiences any deviations from the applicable requirements during the reporting period , include a description of deviations from the applicable requirements , the time periods during which the deviations occurred, and the corrective actions taken. (4) The total fuel use by each affected source boiler 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 through a petition process to be a

non - waste under §241.3(c) , whether the fuel(s) were processed from discarded non

- hazardous secondary materials within the meaning of §241.3 , and the total fuel usage amount with units 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 **252** of **298**

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 a ny 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 specified in paragr aphs (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. (ii) Records documenting the fuel type(s) use d 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 measu re. If you combust non

- hazardous secondary materials that have been determined not to be solid waste**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 **298** pursuant to § 41 2 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 been processed from a discarded non

- hazardous secondary material pursuant to §241.3(b)(2), you must keep records as to how the operations that prod uced 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 calculations and supporting documentation that were done to demonstrate compliance with the mercury emission limits. Supporting documentation should incl ude results of any fuel analyses. You can use the results from one fuel analysis for multiple boilers provided they are 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 minimize emissions in accordance with the general duty 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 **254** of **298** minimize emissions in §63.11205(a), including corrective actions to restore the malfunctio ning boiler, air pollution control, or monitoring equipment to its normal or usual manner of operation. ( 6 ) You 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 time 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 indicated a problem to the time that monitoring indicated proper operation ; and

. (v i ) Maintenance or corrective action taken (if applicable). ( 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 t he date and time of the adjustment, the initial bag**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 **298** 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

correc tive 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 least 2 years after the date of each recorded action according to §63.10(b)(1). You may keep the records offsite off site for the remaining 3 years. ( e ) After A s of December 31, 2011 , and within 60 days after the date of completing each performance evaluation or performance test, as defined in §63.2, conducted to demonstrate compliance with this subpart, the owner or operator of the affected fac ility you must submit relative accuracy test audit (i.e., reference method) data and performance test (i.e., compliance test) data , except opacity data, electronically to EPA’s Central Data Exchange (CDX) using the Electronic Reporting Tool (ERT) or other compatible electronic spreadsheet. Only**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 **256** of **298** data collected using methods compatible with the ERT are subject to this requirement to be submitted electronically into EPA’s WebFIRE database. (f) If you intend to commence or recommence combustion of

so lid waste, you must provide 30 days prior notice of the date upon which you will commence or recommence combustion of solid
waste. The notification must identify: ( 1 ) The name of the owner or operator of the affected source, the location of the source, t he boiler(s) or process heater(s) that will commence burning solid waste, and the date of the notice ; . (2 ) The currently applicable subcategory under this subpart ; . (3) The date on which you became subject to the currently applicable emission limits ; . (4 ) The date upon which you will commence combusting solid
waste. ( g ) If you intend to switch fuels, and this fuel switch may result in the applicability of a different subcategory or a switch out of subpart JJJJJJ due to a switch to 100 percent natural gas , you must provide 30 days prior notice of the date Formatted: Indent: Left: 0", First line: 0.5"**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 **257** of **298** upon which you will switch fuels. The notification must identify: ( 1 ) The name of the owner or operator of the affected source, the location of the source, the boiler(s) that will switch fue ls , and the date of the notice

. (2 ) The currently applicable subcategory under this subpart

. (3) The date on which you became subject to the currently applicable standard s . (4 ) The date upon which you will commence the fuel switch

. § 63.1122 6 How can I assert an a ffirmative d efense if I e xceed

an emission l imit d uring 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 s hall not be available for claims for injunctive relief. (a) Conditions

. To establish the affirmative defense in any action to enforce such a limit, you must timely meet the Formatted: Indent: Left: 0", First line: 0.5"**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 **258** of **298** notification requirements in paragraph (b) of this section, and must prove by a preponderance of evidence that: (1) The excess emissions: (1) t he excess emissions: (i) Were caused by a sudden, 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 planning, proper design or better operation and maintenance practices ; and

. (iii) Did not stem from any activity or event that could have been foreseen and avoided, o r planned for ; and

. (iv) Were not part of a recurring pattern indicative of inadequate design, operation, or maintenance ; and

. (2) Repairs were made as expeditiously as possible when the applicable emission limitations were being exceeded. Off

shift and overtime labor were used, to the extent practicable to make these repairs ; and

. (3) The frequency, amount and duration of the excess emissions (including any bypass) were minimized to the maximum extent practicable during periods of such emissions ; an d

.**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 **259** of **298** (4) If the excess emissions resulted from a bypass of control equipment or a process, then the bypass was unavoidable to prevent loss of life, 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 monitoring and control systems were kept in operation if at all possible ; and

. (7) All of the actions in response to the excess emissions were documented by properly signed, contemporaneous operating logs ; and

. (8) At all times, the facility was operated in a manner consistent with good practices for minimizing emissions ; and

. (9) A written root cause analysis has been prepared to determine, correct, and eliminate the primary causes of the malfunction and the excess emissions resulting from the malfunction event at issue. The analysis shall also specify, using best monitoring methods and engineering judgment, the

amoun t of excess emissions that were the result of the malfunction. (b) Notification

. The owner or operator of the facility Formatted: Underline**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 **260** of **298** experiencing an exceedance of its emission limit(s) during a malfunction shall notify the Administrator by telephone or facsimile (F AX) 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 ass ert an affirmative defense shall also submit a written report to the Administrator within 30 days of the initial occurrence of the exceedance of the standard in
§ 63. 11201 to demonstrate, with all necessary supporting documentation, that it has met the requ irements 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 7 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 a nd enforced by EPA or a delegated authority such as your State s tate , local, or tribal agency. If the EPA Administrator has delegated authority to
your State s tate , local, or tribal agency, then that agency has the authority to implement and enforce this su bpart. You should**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 **261** of **298** contact your EPA Regional Office to find out if implementation and enforcement of this subpart is delegated to your State s tate , local, or tribal agency. (b) In delegating implementation and enforcement authority of this subpart to a S tate s tate , 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 s tate , local, or tribal agency. (c) The authorities that cannot be delegated to
State s tate , 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 monitoring under §63.8(f). A “major change to monitoring” is defined in §63.90. (5) Approval of major change to recordkeeping 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 **262** of **298** reporting under §63.10(f). A “major change to recordkeeping/reporting” is defined in §63.90. §63.11237 What definitions apply to this subpart? Terms used in this subpart are defined in the CAA C lean A ir

A ct , in §63.2 (the General Provisions), and in this section as follows: Affirmative defense means, in the context of an enforcement proceeding, a response or defense put forward by a defendant, regarding which the defendant has the burden of proof, and the merits of which are independently and objectively evaluated in a judicial or administrativ e proceeding. Annual heat input basis means the 12 months preceding the compliance demonstration. Bag leak detection system means an instrument a group of instrument s that is capable of monitoring particulate matter loadings in the exhaust of a fabric fil ter (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.**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 **263** of **298** Biomass means any biomass

- 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 sander dust , chips, scraps, slabs, millings, and shavings); animal manure, including 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 bean hulls and grounds. This definition of biomass is not intended to suggest that these materials are or are not solid waste. Biomass subcategory includes any boiler that burns at leas t 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 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 boiler and associated components, such as, the feedwater system, the combustion air system, the boiler fuel system (including burners), blowdown system,**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 **264** of **298** combustion control system, steam system, and condensate return system. Coal means all solid fuels classifiable as anthracite, bitumino us, 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 establishments such as hotels, restaurants, and laundries to provide electricity, 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 including, bu t not limited to, any**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 **265** of **298** 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 affecte d 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 the standards

. Dry scrubber

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. An electro static Formatted: ___GHG PARAGRAPH, Line spacing: single, Don't adjust space between Latin and Asian text, Tab stops: Not at 0" + 0.5" + 1" + 1.5" + 2" + 2.5" + 3" + 3.5" + 4" + 4.5" + 5" + 5.5" + 6" + 6.5" 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. A dry scrubber is a dry control system.**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 **266** of **298** precipitator is a dry control system, except when it is operated with a wet scrubber. 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

- term 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 following only as this term is used in Table 3 to this subpart

. :

a. (1 ) Energy assessment 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 accounting 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 heaters u sing 0.3 to 1 TBtu/year will be three days 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 opportunities, within t he limit of performing a 3 one day energy assessment. Formatted: Underline

Formatted: Normal, Indent: First line: 0.5", No bullets or numbering**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 **267** of **298** (2) Energy a ssessment for facilities with affected boilers and process heaters using 0.3 to 1 TBtu/year will be three days 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 opportunities, within the limit of performing a 3

- day energy assessment.

c. (3) Energy assessment for facilities with affected boilers an d 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 the 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 heating, ventilation, and air

conditioning (HVAC) systems; hot heater systems;, building envelop; and lighting. Equivale nt means the following only as this term is used in Table 5 to this subpart : (1) An equivalent sample collection procedure means a published voluntary consensus standard or practice (VCS) or EPA method that includes collection of a minimum of three Formatted: Normal, Indent: First line: 0.5", No bullets or numbering

Formatted: Indent: First line: 0.5"**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 **268** of **298** composite fuel samples, with each composite consisting of a minimum of three increments collected at approximately equal intervals over the test period. (2) An equivalent sample compositing procedure means a published VCS or EPA method to systematically mix and obtain a representative subsample (part) of the composite sample. (3) An equivalent sample preparation procedure means a published VCS or EPA method that: Clearly states that the standard, practice or method is appropriate for the pollutant and the fuel matrix; or is cited as an appropriate sample preparation standard, practice or method for the pollutant in the chosen VCS or EPA determinative or analytical method. (4) An equivalent procedure for determining heat content means a published VCS o r EPA method to obtain gross calorific (or higher heating) value. (5) An equivalent procedure for determining fuel moisture content means a published VCS or EPA method to obtain moisture content. If the sample analysis plan calls for determining
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 metals analysis is done on an "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 **269** of **298** received" basis, a separate aliquot can be dried to determine moisture content an d the me rcury concentration mathematically adjusted to a dry basis. (6) An equivalent mercury determinative or analytical procedure means a published 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. Fabric 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. A fabric filter is a dry control system. Federally enforceable means all limitations and conditions that are enforceable by the EPA Administrator, including the requirements of 40 CFR part 60 and 40 CFR part 61, requirements within any applicable State s tate 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 means each category of fuels that share a common name or classification. Examples include, but are not limited to, bituminous coal, subbituminous sub

- bituminous coal, lignite, Formatted: Font: 10 pt

Formatted: Font: 10 pt**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 **270** of **298** anthracite, biomass, distillate oil, residua l oil. Individual fuel types received from different suppliers are not considered new fuel types. Gaseous fuels includes, but is not limited to, natural gas, process gas, landfill gas, coal derived gas, refinery gas, hydrogen, and biogas.
Gas

- fired bo iler 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 c ombined 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 heat input from preheated combustion air, recirculated flue gases, or returned condensate. Hot water heater mean s 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 withdrawn 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 )
.**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 **271** of **298** Industrial boiler means a boiler used in manufacturing, processing, mining, and refining or any other indust ry to provide steam, hot water, and/or electricity. Institutional boiler means a boiler used in institutional establishments such as medical centers, 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 biofuels, and biodiesel. Minimum scrubber pressure drop activated carbon i njection rate 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 limit. Minimum sorbent flow rate means the boiler load fraction (percent) multiplied by 90 percent of the test lowest 1

- hour average sorbent (or activated carbon ) injection rate measured according to Table 3 6 to this subpart during the most recent performance stack test demonstrating compliance with the applica ble emission limits. Formatted: ___GHG PARAGRAPH, Line spacing: single, Don't adjust space between Latin and Asian text**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 **272** of **298** Minimum voltage or amperage scrubber pressure drop

means 90 percent of the test lowest 1

- hour average voltage or amperage to the electrostatic precipitator scrubber pressure drop measured according to Table 3 6 to this subpart during the most recent performance stack test demonstrating compliance with the applicable emission limit. Minimum sorbent flow rate means the boiler load (percent) multiplied by the lowest 1

- hour average sorbent (or activated carbon ) injection rate measured according to Table 6 to this subpart during the most recent performance stack test demonstrating compliance with the applicable emission limits. Minimum voltage or amperage means the lowest 1

- hour average voltage or amperage to the electrostatic precipitator measured according to Table 6 to this subpart during the most recent performance stack test demonstrating compliance with the applicable emission limits. Natural gas means: (1) A naturally occurring mixture of hydrocarbon and nonhydrocarbon gases found in geologic formations beneath the earth’s surface, of which the principal constituent is methane , including intermediate gas streams generated during processing of natural gas at production s ites or at gas processing plants ; Formatted: Font: Not Italic**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 **273** of **298**

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 between 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 testing , not to exceed 48 hours duri ng any calendar year, of liquid fuel 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.**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 **274** of **298** Particulate matter (PM) means any finely divided s olid 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 st ack 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 affected facility is halted for reason s 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 defini tion. 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 energy systems, such as, a person who have successfully completed the DOE D epartment of E nergy Qualified Specialist program for all systems, Certified Energy Managers certified by the Association of Energy Engineers, or a pe rson who has**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 **275** of **298** demonstrated capabilities to perform and evaluate a full assessment 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 are not limited
to :

a. Boiler combustion management

. b. Boiler thermal energy 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 fired 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 the assessment activities, data analysis, and report preparation

. b

. F amiliarity with operating and maintenance practices for steam or process heating systems
. Formatted: Line spacing: Double

Formatted: Font color: Auto Formatted: Indent: Left: 0.5", Hanging: 0.31"**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 **276** of **298** 1. additional A dditional potential steam system improvement opportunities including improving steam turbine operations and reducing steam demand

. 2. additional A dditional process heating system opportunities including effective utilization of waste heat and use of proper process heating methods

. 3. boiler B oiler

- steam turbine cogeneration systems , . 4. industry I ndustry specific steam end

- use systems 4. Qualified personnel 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 Engineers, or the equ ivalent

. Responsible official means responsible official as defined in 40 CFR § 70.2. 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 usab le heat. Waste heat boilers are also referred to as heat recovery steam generators. Work practice standard means any design, equipment, work practice, or operational standard, or combination thereof, which Formatted: Indent: Left: 0.88", Tab stops: 1.13", Left + Not at 1.31" + 2.5"

Formatted: Indent: Left: 0.88", Tab stops: 1.13", List tab + Not at 1.56" + 2.5"

Formatted: Indent: Left: 0.88", Hanging: 0.44", Tab stops: 1.13", Left + Not at 2.5"

Formatted: List Paragraph, Indent: Left: 0.88", Hanging: 0.44", Don't add space between paragraphs of the same style, Line spacing: Double, Numbered + Level: 5 + Numbering Style: 1, 2, 3,

... + Start at: 1 + Alignment: Left + Aligned at: 2.25" + Tab after: 2.5" + Indent at: 2.5", Tab stops: 1.13", List tab + Not at 2.5" Formatted: Font: Courier New, Font color: Black Formatted: Font color: Black**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 **277** of **298** is promulgated pursuant to section 112(h) of th e CAA. C lean A ir

A ct
.
**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, except 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. b. Mercury 0.0000048 lb per MMBtu of heat input.

c. Carbon Monoxide 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. b. Mercury 0.0000048 lb per MMBtu of heat input. Formatted: Left

Merged Cells Formatted Table

Formatted: Indent: Left: 0", First line: 0"

Formatted Table

Formatted: Tab stops: 0.43", Left + Not at 0.5"**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 **278** of **298**

c. Carbon Monoxide 400 ppm by volume on a dry basis corrected to 3 percent oxygen. 3. New biomass

fired boiler with heat input capacity of 30 millionBtu per hour or greater a. Particulate Matter 0.03 lb per MMBtu of heat input.

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. Particulate 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 corrected to 3 percent oxygen. Formatted: Tab stops: 0.43", Left + Not at 0.5"

Merged Cells Formatted Table**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 **279** of **298**
b. Carbon Monoxide 400 ppm by volume on a dry basis corrected 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 reduction measures, and management practices : **If your boiler is in this su**  **bcategory... You must meet the following...**  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 startup and shutdown periods following the manufacturer’s recommended procedures. If manufacturer’s recommended procedures are not available, you must follow recommended procedures for a unit of similar design for which manufacturer’s recommended procedures are available. 2 . Existing or new coal ( units with heat input capac ity 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 a qualified personnel which includes:

( energy assessor . An energy assessment completed on or after January 1 ) a , 2008, that meets the energy assessment requirements in this table satisfies the energy Formatted: Left

Formatted: Font color: Black Formatted: Font color: Black**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 **280** of **298** assessment requirement. The energy assessment must include: (1) A visual inspection of the boiler system. (2) establish An evaluation of operating characteristics o f the facility, energy system specifications of energy using systems , operating and maintenance procedures, and unusual operating constraints, (3) identify I nventory of major systems consuming energy from affected boiler(s) , (4) a A review of available architectural and engineering plans, facility operation and maintenance procedures and logs, and fuel usage, (5) a A list of major energy conservation measures, (6) A list of t he energy savings potential of the energy conservation measures identified, (7) a A comprehensive report detailing the ways to improve efficiency, the cost of specific improvements, benefits, and the time frame for recouping those investments,

**Table 3 to Subpart 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 limits...**  1. Fabric filter a. Maintain opacity to less than Formatted: Left**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 **281** of **298** control 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 detection 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 minimum 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 above 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

. When your boiler operates at lower loads, multiply your sorbent or carbon injection rate by the load fraction (e.g., actual heat input divided by the heat input during performance stack test, for 50 percent load, m ultiply the injection rate operating limit by 0.5). 5. Any other add

- on 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 averag 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 **282** of **298** 6. Fuel analysis Maintain the fuel type or fuel mixture (annual average) such that the mercury emission rates calculated according to §63.11211( b ) is less than the applicable emission limits for mercury. 7. Performance stack testing For boilers that demonstrate compliance with a performance stack test, maintain the operating load of each unit such that is does not exceed 110 percent of the average operating load recorded during the most recent performance stack test. 8. Continuous Oxygen Monitor For boilers that demonstrate compliance with an oxygen monitor, maintain the oxygen level of the stack gas such that it is not below 90 percent of the average oxygen concentration measured during the most recent CO performance stack test.

**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**  **pollutan t...**  **You must... Using...**  1.Particulate Matter a. Select sampling ports location and the number of traverse points. Method 1 in appendix A

- 1 to part 60 of this chapter. Formatted: Left

Formatted Table**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 **283** of **298** b. Determine velocity and volumetric flow

rate of the stack gas. Method 2, 2F, or 2G in appendix A

- 2 to part 60 of this chapter. 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.

d. Measure the moisture content of the stack gas

e. Measure the particulate matter emission concentration.

f. Convert emissions concentration to lb/ MMBtu emission rates. 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

- 2 to part 60 of this chapter, or ASTM D6522

- 00 ( IBR, see §63.14(b)), Reapprov ed 2005) a , or ANSI/ ASME 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

1981 a

. Merged Cells Formatted Table

Formatted: Space Before: 5 pt, After: 0 pt, Tab stops: Not at 0.5" Formatted: Space After: 0 pt**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 **284** of **298** d. Measure the moisture content of the stack gas. Method 4 in appendix A

- 3 to part 60 of this chapter. e. Measure the particulate matter emission concentration. Method 5 or 17 (positive pressure fabric filters must use Method 5D) in appendix A

- 3 and A

6 to part 60 of this chapter. f. Convert emissions concentration to lb/ MMBtu emission rates. Method 19 F

- factor methodology in appendix A

- 7 to part 60 of this chapter. 2. Mercury a. Select sampling ports location and the number of traverse points. Method 1 in appendix A

- 1 to part 60 of this chapter. b. Determine velocity and volumetric flow

rate of the stack gas. Method 2, 2F, or 2G in appendix A

- 2 to part 60 of this chapter. c. Determine oxygen and carbon dioxide concentrations of the stack gas. Method 3A or 3B in appendix A

- 2 to part 60 of this chapter, or ASTM D6522

- 00 (Reapproved 2005) a , or ANSI/ ASME PTC 19.10

- 1981 a

. d. Measure the moisture content of the stack gas. Method 4 in appendix A

- 3 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 **285** of **298**
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 dioxide 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 29 or 30B 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 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

- 8 to part 60 of this chapter or Meth od 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 02 a

. Merged Cells Formatted: Indent: Left: 0", Hanging: 0.18", Tab stops: 0.18", Left + Not at 0.29" Formatted Table

Formatted: Space After: 0 pt

Formatted: Space After: 0 pt**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 **286** of **298** f. Convert emissions concentration to lb/ MMBtu emission rates. Method 19 F

- factor methodology in appendix A

- 7 to part 60 of this chapter. 3. Carbon Monoxide a. Select the sampling ports location an d the number of traverse points Method 1 in appendix A

- 1 to part 60 of this chapter. 3. Carbon 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

- 2 to part 60 of this chapter, or ASTM D6522

- 00 ( IBR, see §63.14(b)), Reapprov ed 2005) a , or ANSI/ ASME PTC 19 , Part
. 10 (1981)(IBR, see §63.14(i)). Method 4 in appendix A to part 60 of 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).

- 1981 a

. c. Measure the moisture content of the stack gas. Method 4 in appendix A

- 3 to part 60 of this chapter. Merged Cells Formatted: Space Before: 0 pt, After: 0 pt, Tab stops: 0.5", Left + 2", Left Formatted Table

Formatted: Space After: 0 pt**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 **287** of **298** d. Measure the carbon monoxide emission concentration. Method 10, 10A, or 10B in appendix A

- 4 to part 60 of this chapter or ASTM D6522

- 00 ( Reapproved 2005) a

. a Incorporated by reference, see §63.14

**Table 5 to Subpart JJJJJJ of Part 63 —**  **Fuel Analysis Requirements**  As stated in §63.11213, you must comply with the following requirements 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( b ) or ASTM D2234

- D2234M a (for coal) or ASTM D6323 a (for biomass) or equivalent. b. Compose fuel samples. Procedure in §63.11213( b ) or equivalent. Formatted: Left**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 **288** of **298**
1. Mercury a. Collect fuel samples.

b. Compose fuel samples.

c. Prepare composited fuel samples.

d. Determine heat content of the fuel type.

e. Determine moisture content of the fuel type.

f. Measure mercury concentration in fuel sample. Procedure in §63.11213(c) or ASTM D2234

- D2234M

- 03 € 1 (for coal)(IBR, see §63.14(b)) or ASTM D6323

- 98 (2003)(for biomass)(IBR, see §63.14(b)) or equivalent. Procedure in §63.11213(c) or equivalent.

EPA SW

- 846

- 3050B 3050B a (for solid samples) or EPA SW

- 846

- 3020A 3020A a (for liquid samples) or ASTM D2013

- 04 /D2013 M a (for coal )(IBR, see §63.14(b)) ) or ASTM D5198

- 92 (2003) D5198 a (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 ASTM E871

- 82 (1998)(IBR, see §63.14(b)) or equivalent.

ASTM D6722

- 01 (for coal)(IBR, see §63.14(b)) c or SW

- 8 46

- 7471A (for solid samples) or SW

- 846 7470A (for liquid samples ) or equivalent. Formatted Table

Formatted: Space After: 0 pt Formatted: Space Before: 5 pt, After: 0 pt**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 **289** of **298**
d. Determine heat content of the fuel type. ASTM D5865 a (for coal) or ASTM E711 a (for biomass) or equivalent.
e. Determine moisture content of the fuel type. ASTM D3173 a or ASTM E871 a or equivalent.

f. Measure mercury concentration in fuel sample. ASTM D6722 a (for coal) or EPA SW

- 846

- 7471 B a (for solid samples) or EPA SW

- 846

- 7470A a (for liquid samples) or equivalent. 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 ” a Incorporated by reference, see §63.14
.

**Table 6 to Subpart JJJJJJ of Part 63 —**  **Establishing Operating Limits**  As stated in §63. 11211 , you must comply with the following requirements for establishing operating limits: **If you have an**  **applicable**

**emission limit for** 

**. . . And your**  **operating limits are** 

**based on**

**. . . You must...**  **Using . . . According to**  **the following**  **requirements** Formatted: Font: 11 pt, Not Bold Formatted: Tab stops: Not at 0" + 0.29" + 0.5" + 1" + 1.5" + 2" + 2.5" + 3" + 3.5" + 4" + 4.5" + 5" + 5.5" + 6" + 6.5" Formatted: Font: Courier New**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 **290** of **298 If you have**  **an applicable** 

**emission limit for** 

**. . . And your**  **operating limits are** 

**based on**

**. . . You must...**  **Using . . . According to**  **the following**  **requirements** 1. Particulate matter or mercury a. Wet scrubber operating parameters i. Establish a site

specific minimum pressure drop and minimum flow rate operating limit according to §63. 11211 (b) (1) Data from the pressure drop and liquid flow rate monitors and the particulate matter or mercury performance stack test (a) You must collect pressure drop and liquid flow

rate data every 15 minutes during the entire period of the performance stack tests; (b) Determine the average pressure drop and liquid flow

rate for each individual test run in the three

run performance stack test by computing the average of all the 15

- minute readings taken during each test run.**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 **291** of **298 If you have**  **an applicable** 

**emission limit for** 

**. . . And your**  **operating limits are** 

**based on**

**. . . You must...**  **Using . . . According to**  **the following**  **requirements** b. Electrostatic precipitator operating parameters (option only for units that operate wet scrubbers) i. Establish a site

specific minim um voltage and secondary amperage (or total power input) according to §63. 11211 (b) (1) Data from the voltage and secondary amperage monitors during the particulate matter or mercury performance stack test (a) You must collect voltage and secondary amperage or total power input data every 15 minutes during the entire period of the performance stack tests; (b) Determine the average voltage and secondary amperage or total power input for each individual test run in the three

run performance stack test by computing the average of all the 15

- minute readings taken during each test run.**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 **292** of **298 If you have**  **an applicable** 

**emission limit for** 

**. . . And your**  **operating limits are** 

**based on**

**. . . You must...**  **Using . . . According to**  **the following**  **requirements** 2 . Mercury a. Activated carbon injection i. Establish a site

specific minimum activated carbon injection rate op erating limit according to §63.11211 (b) (1) Data from the a ctivated carbon rate monitors and mercury performance stack tests (a) You must collect activated carbon injection rate data every 15 minutes during the entire period of the performance stack tests; (b) Determine the average activated carbon injection rate for each individual test run in the three

run performance stack test by computing the average of all the 15

- minute readings taken during each test run.**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 **293** of **298 If you have**  **an applicable** 

**emission limit for** 

**. . . And your**  **operating limits are** 

**based on**

**. . . You must...**  **Using . . . According to**  **the following**  **requirements** (c) Determine the average of the three test run averages established during the performance stack test as your operating limit. When your unit operates at lower loads, multiply your activated carbon injection rate by the load fraction (e.g., actual heat input divided by heat input during performance stack test, for 50 percent load, multiply the injection rate operating limit by 0.5) to determine the required injection**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 **294** of **298**

**Table 7**  **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.

§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 malfunctions ASAP No.

§63.6(e)(3) SSM Plan No. §63.6(f)(1) SSM exemption No. §63.6(h)(1) S SM exemption No. Formatted: Left**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 **295** of **298**
§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 Requirements 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.

§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.**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 **296** of **298** §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 recordkeeping 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.
§63.10(c)(15) Allows u se of SSM p lan No.
§63.10(d)(1) and (2) General reporting 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 **297** of **298**
§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 Provisions Yes.

§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.**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 **298** of **298**