



EO12866 NESHAP for Area Sources-Industrial Commercial Institutional Boiler and Process Heaters RIN 2060-AR14 Final Rule  -  Reconsideration 20120504

                                                                      6560-50-P
                        ENVIRONMENTAL PROTECTION AGENCY
                                40 CFR Part 63
                      [EPA-HQ-OAR-2006-0790; FRL-      ]
                                 RIN 2060-AR14
National Emission Standards for Hazardous Air Pollutants for Area Sources: Industrial, Commercial, and Institutional Boilers

AGENCY: Environmental Protection Agency (EPA).
ACTION: Final rule; notice of final action on reconsideration.
SUMMARY: In this action, the EPA is finalizing amendments for emission standards to control hazardous air pollutants from new and existing industrial, commercial and institutional boilers at area sources of hazardous air pollutants, which were issued under section 112 of the Clean Air Act. As part of this action, the EPA is amending effective dates of the standard and making technical corrections to the final rule to clarify definitions, references, applicability and compliance issues raised by petitioners and other stakeholders affected by the rule. This action also takes final action on reconsideration of specific elements of the final rule. 
DATES: This final rule is effective on [INSERT THE DATE OF PUBLICATION IN THE FEDERAL REGISTER].
ADDRESSES: The EPA established a single docket under Docket ID No. EPA-HQ-OAR-2006-0790 for this action. All documents in the docket are listed on the http://www.regulations.gov website. Although listed in the index, some information is not publicly available, e.g., confidential business information or other information whose disclosure is restricted by statute. Certain other material, such as copyrighted material, is not placed on the Internet and will be publicly available only in hard copy form. Publicly available docket materials are available either electronically through http://www.regulations.gov or in hard copy at the EPA's Docket Center, Public Reading Room, EPA West Building, Room 3334, 1301 Constitution Avenue, NW, Washington, DC 20004. This Docket Facility is open from 8:30 a.m. to 4:30 p.m., Monday through Friday, excluding legal holidays. The telephone number for the Public Reading Room is (202) 566 - 1744, and the telephone number for the Air Docket is (202) 566 - 1741.
FOR FURTHER INFORMATION CONTACT: Mr. James Eddinger, Energy Strategies Group (D243-01), Sector Policies and Programs Division, Office of Air Quality Planning and Standards, Environmental Protection Agency, Research Triangle Park, North Carolina 27711; telephone number: (919) 541-5426; fax number: (919) 541-5450; email address: eddinger.jim@epa.gov or Ms. Mary Johnson, Energy Strategies Group (D243-01), Sector Policies and Programs Division, Office of Air Quality Planning and Standards, Environmental Protection Agency, Research Triangle Park, North Carolina 27711; telephone number: (919) 541-5025; fax number: (919) 541-5450; email address: johnson.mary@epa.gov. 
EXECUTIVE SUMMARY:
Purpose of this Regulatory Action
The EPA is taking final action on its proposed reconsideration of certain provisions of its March 21, 2011, final rule that established emission standards for new and existing industrial, commercial, and institutional boilers located at area source facilities pursuant to CAA sections 112(c)(3), 112(c)(6), and 112(k)(3)(B). 
Section 112(d) of the CAA requires the EPA to regulate HAP from both major and area stationary sources. Section 112(d)(5) of the CAA allows the EPA to establish standards for area sources of HAP "which provide for the use of generally available control technologies (GACT) or management practices by such sources to reduce emissions of hazardous air pollutants." While GACT serves as the basis for standards of most emissions from area sources, two pollutants, POM as 7-PAH and Hg must be regulated based on the performance of MACT. These two pollutants are regulated based on MACT because area source industrial, commercial and institutional boilers combusting coal were listed under section 112(c)(6) of the CAA due to the source categories' emissions of POM and Hg. Sections 112(d)(2) or (d)(4) of the CAA require the EPA to regulate pollutants listed under section 112(c)(6) based on MACT. The final rule meets the requirements of section 112(d) of the CAA by setting MACT standards for Hg and CO  --  as a surrogate for POM for units in the coal-fired subcategory. Further, the final rule sets standards based on GACT for all of the other urban HAP emitted from coal-fired boilers that pose the greatest public health risk, pursuant to section 112(c)(3) of the CAA. In addition, the final rule sets standards based on GACT for boilers combusting oil or biomass for all urban HAP, including Hg, arsenic, beryllium, cadmium, lead, chromium, manganese, nickel, POM, ethylene dioxide, and PCBs.
In developing these MACT standards for coal-fired boilers, the EPA also considered section 112(h) of the CAA, which allows the EPA to establish work practice standards in lieu of numerical emission limits only in cases where the agency determines that it is not feasible to prescribe or enforce an emission standard, including circumstances in which the agency determines that the application of measurement methodology is not practicable due to technological and economic limitations. The EPA has found that work practices are appropriate under certain circumstances, pursuant to section 112(h) of the CAA, in the form of periodic tune-ups for small boilers.
This final rule replaces the provisions of the final rule issued by the EPA on March 21, 2011, for those provisions which the EPA is revising in this action. 
Summary of Major Provisions
In general, the final rule as amended by this action requires facilities classified as area sources of HAP with affected boilers to reduce emissions of harmful toxic air emissions from these combustion sources, improving air quality, and protecting public health in communities where these facilities are located. Recognizing the diversity of this source category and the multiple sectors of the economy this rule effects, in the March 2011 final rule, the EPA established subcategories for boilers based on the design of the combustion equipment and operating schedules of the unit.
Numerical emission limits, based on MACT, were established for Hg and CO at new and existing coal-fired boilers with a design capacity of 10 MMBtu/hr or more. Small coal units with a design capacity of less than 10 MMBtu/hr are subject to periodic tune-up work practices for CO and Hg in lieu of numeric emission limits because the EPA found that it was technologically and economically impracticable to apply measurement methodology to these small sources, pursuant to section 112(h).
Numerical emission limits, based on GACT, were established for PM as a surrogate for other urban HAP for new coal, biomass and oil-fired boilers with a design heat input capacity of 10 MMBtu/hr or greater. Existing biomass and oil-fired boilers and new small biomass- and oil-fired boilers are subject to periodic tune-up management practices for PM based on GACT. New and existing seasonal boilers firing oil or biomass are subject to periodic tune-up management practices, based on GACT, in lieu of numerical emission limits, for all HAP. 
The EPA also finalized alternative compliance options for the numeric CO emission limit. Coal-fired boilers subject to CO emission limits can comply with this limit using a periodic stack test and continuous parametric monitoring, or by using CEMS. This alternative standard is based on a 10-day rolling average and provides additional compliance flexibility to sources with existing CO CEMS equipment or load following operations. The numerical emission limits in this final rule apply at all times except during periods of startup and shutdown, in which alternative work practice standards apply since the EPA has determined that it is technologically and economically impracticable to apply measurement methodology during periods of startup and shutdown. The rule also requires periodic testing, parametric monitoring, recordkeeping and reporting to ensure compliance with the emission standards and work practices. The final rule also employs a one-time energy assessment beyond-the-floor standard on all existing facilities that have one or more existing coal, biomass or oil-fired boilers with a heat input capacity of 10 MMBtu/hr or greater. The length of time needed to conduct the energy assessment depends on the total energy consumption of the affected boilers at the facility.
The compliance dates for the rule are March 21, 2014, for existing sources, May 20, 2011, for new sources that started up on or before May 20, 2011, and upon startup for new sources that start up after May 20, 2011. New sources are defined as sources that began operation after June 4, 2010.
Costs and Benefits
The amendments contained in this final action are corrections that are intended to clarify, but not change, the coverage of the final rule. The final rule will affect approximately an estimated 180,000 existing area source boilers and the EPA projects approximately an additional 6,800 new boilers to be subject to the rule over the initial 3-year period. The clarifications and corrections should make it easier for owners and operators and for local and state authorities to understand and implement the requirements. As compared to the control costs estimated in the March 2011 final rule, these amendments will result in a decrease in the capital and annual costs due to the increase in emission limits and the decrease in burden on small facilities. A more detailed discussion of the costs and benefits of the final rule is provided at 76 FR 15579, March 21, 2011, and 76 FR 80542, December 23, 2011. Section V of this preamble discusses the impacts of the amendments.
Exposure to toxic air pollutants regulated under this standard can cause respiratory problems such as bronchitis and asthma, and other serious health issues.
SUPPLEMENTARY INFORMATION:
Acronyms and Abbreviations. The following acronyms and abbreviations are used in this document.
7-PAH	7-polynuclear aromatic hydrocarbons
ASTM	American Society for Testing and Materials
Btu	British thermal unit
CO	carbon monoxide
CEMS	continuous emissions monitoring system
CDX	Central Data Exchange
CAA	Clean Air Act
CFR	Code of Federal Regulations 
COMS	Continuous Opacity Monitoring System
CPMS	continuous parameter monitoring system
DOE	Department of Energy
ERT	Electronic Reporting Tool
ESP	Electrostatic Precipitator
FR	Federal Register
GACT	generally available control technologies
HAP	hazardous air pollutants
Hg	mercury
HQ	Headquarters
ISO	International Standards Organization
lb	pounds
MACT	Maximum Achievable Control Technology
MMBtu	million British thermal units
NAICS	North American Industry Classification System
NESHAP	National Emission Standards For Hazardous Air Pollutants 
NTTAA	National Technology Transfer and Advancement Act
OMB	Office of Management and Budget
PM	particulate matter
PCBs	polychlorinated biphenyls
POM	polycyclic organic matter
ppm	parts per million
RFA	Regulatory Flexibility Act
RIN	Regulatory Information Number 
TBtu	Trillion British thermal unit
TTN	Technology Transfer Network
tpy	tons per year
UMRA	Unfunded Mandates Reform Act of 1995
UPL	upper prediction limit
VCS	Voluntary Consensus Standards
WWW	Worldwide Web 

Organization of this Document. The information presented in 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
III. Summary of Final Action on Reconsideration
A. Affected Sources
B. Source Category Exclusions
C. Emission Limits
D. Tune-up Work Practice and Management Practice Standards
E. Energy Assessment Work Practice and Management Practice Standards
F. GACT-Based Standards
G. Initial Compliance
H. Operating Limits
I. Continuous Compliance
J. Periods of Startup, Shutdown and Malfunction
K. Notification, Recordkeeping, and Reporting Requirements
L. Title V Permitting Requirements
M. Definition of Period of Gas Curtailment or Supply Interruption
N. Other Miscellaneous Technical Corrections
IV. Summary of Significant Changes Since Proposed Action on Reconsideration
A. Applicability
B. Tune-Up Requirements
C. Energy Assessment
D. Clarification of Oxygen Concentration Operating Limits
E. Definitions Regarding Averaging Times
F. Continuous Compliance
G. Fuel Sampling Frequency
H. Performance Testing Frequency
I. Startup and Shutdown Definitions
J. Notification of Fuel Change or Physical Change
K. Miscellaneous Definitions
V. Other Actions the EPA is Taking
VI. Impacts associated with this Final Rule
VII. Statutory and Executive Order Reviews
A. Executive Order 12866: Regulatory Planning and Review and Executive Order 13563: Improving Regulation and Regulatory Review
B. Paperwork Reduction Act
C. Regulatory Flexibility Act
D. Unfunded Mandates Reform Act
E. Executive Order 13132: Federalism
F. Executive Order 13175: Consultation and Coordination with Indian Tribal Governments
G. Executive Order 13045: Protection of Children from Environmental Health Risks and Safety Risks
H. Executive Order 13211: Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution, or Use
I. National Technology Transfer and Advancement Act
J. Executive Order 12898: Federal Actions to Address Environmental Justice in Minority Populations and Low-Income Populations
K. Congressional Review Act

I. General Information
A. Does this action apply to me?
The regulated categories and entities potentially affected by this action include:
                               Industry Category
                                 NAICS Code[a]
                        Examples of Regulated Entities
Any area source facility using a boiler as defined in the final rule
321
Wood product manufacturing.

11
Agriculture, greenhouses.

311
Food manufacturing.

327
Nonmetallic mineral product
manufacturing.

424
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.

22111
Electric power generation.
 [a] 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 regulated by this reconsideration action. To determine whether your facility may be affected by this reconsideration action, you should examine the applicability criteria in 40 CFR 63.11193 of subpart JJJJJJ (National Emission Standards for Hazardous Air Pollutants for Industrial, Commercial, and Institutional Boilers Area Sources). If you have any questions regarding the applicability of the final rule to a particular entity, consult either the air permit authority for the entity or your EPA regional representative, as listed in 40 CFR 63.13 of subpart A (General Provisions).
B. Where can I get a copy of this document?
In addition to being available in the docket, an electronic copy of this action will also be available on the WWW through the TTN. Following signature, a copy of the action will be posted on the TTN's policy and guidance page for newly proposed or promulgated rules at the following address: http://www.epa.gov/ttn/oarpg/. The TTN provides information and technology exchange in various areas of air pollution control.
C. Judicial Review
Under the CAA section 307(b)(1), 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 by May 20, 2011. 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.
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
Section 112(d) of the CAA requires the EPA to establish NESHAP for both major and area sources of HAP that are listed for regulation under CAA section 112(c). A major source is any stationary source that emits or has the potential to emit 10 tpy or more of any single HAP or 25 tpy or more of any combination of HAP. An area source is a stationary source that is not a major source.
On March 21, 2011 (76 FR 15554), the EPA issued the NESHAP for industrial, commercial and institutional area source boilers pursuant to CAA sections 112(c)(3), 112(c)(6), and 112(k)(3)(B). 
CAA section 112(k)(3)(B) directs the EPA to identify at least 30 HAP that, as a result of emissions from area sources, pose the greatest threat to public health in the largest number of urban areas. The EPA implemented this provision in 1999 in the Integrated Urban Air Toxics Strategy, (64 FR 38715, July 19, 1999) (Strategy). Specifically, in the Strategy, the 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." Section 112(c)(3) of the CAA requires the EPA to list sufficient categories or subcategories of area sources to ensure that area sources representing 90 percent of the emissions of the 30 urban HAP are subject to regulation. Under CAA section 112(d)(5), the EPA may elect to promulgate standards or requirements for area sources "which provide for the use of generally available control technologies ("GACT") or management practices by such sources to reduce emissions of hazardous air pollutants."
While GACT may be a basis for standards for most types of HAP emitted from area sources, CAA section 112(c)(6) requires that the EPA list categories and subcategories of sources assuring that sources accounting for not less than 90 percent of the aggregate emissions of each of seven specified HAP are subject to standards under CAA sections 112(d)(2) or (d)(4), which require the application of the more stringent MACT. The seven HAP specified in CAA section 112(c)(6) are as follows: alkylated lead compounds, POM as PAH, hexachlorobenzene, Hg, PCBs, 2,3,7,8-tetrachlorodibenzofurans, and 2,3,7,8-tetrachlorodibenzo-p-dioxin.
As noted in the preamble to the final rule, (76 FR 15556, March 21, 2011), we listed area source industrial boilers and commercial/institutional boilers combusting coal under CAA section 112(c)(6) based on the source categories' contribution of mercury and POM, and under CAA section 112(c)(3) for their contribution of arsenic, beryllium, cadmium, lead, chromium, manganese, nickel, ethylene dioxide, and PCBs, as well as Hg and POM. We promulgated final standards for coal-fired area source boilers to reflect the application of MACT for Hg and POM, and to reflect GACT for the urban HAP other than Hg and POM. 
We listed industrial and commercial/institutional boilers combusting oil or biomass under CAA section 112(c)(3) for their contribution of Hg, arsenic, beryllium, cadmium, lead, chromium, manganese, nickel, POM, ethylene dioxide, and PCBs. For boilers firing oil or biomass, the final standards reflect GACT for all of the urban HAP.
On March 21, 2011, we also published a notice to initiate the reconsideration of certain aspects of the final rule for area source industrial, commercial and institutional boilers (76 FR 15266). The reconsideration notice identified several provisions of the final rule where additional public comment was appropriate. The notice also identified several issues of central relevance to the rulemaking where reconsideration was appropriate under CAA section 307(d). 
Following promulgation of the final rule, the EPA also received petitions for reconsideration from the following organizations (Petitioners): American Sugar Cane League of the U.S.A., Alaska Oil and Gas Association, American Coke and Coal Chemicals Institute, American Iron and Steel Institute, American Petroleum Institute, Council of Industrial Boiler Owners, Industry Coalition (American Forest and Paper Association (AF&PA) et. al.), National Petrochemical and Refiners Association, Sierra Club, and the State of Washington Department of Ecology. Petitioners, pursuant to CAA section 307(d)(7)(B), requested that the EPA reconsider numerous provisions in the rules. On December 23, 2011, the EPA granted the petitions for reconsideration on certain issues, and proposed certain revisions to the final rule in response to the reconsideration petitions and to address the issues that the EPA previously identified as warranting reconsideration. That proposal solicited comment on several specific aspects of the rule, including:
Establishing separate requirements for seasonally operated boilers.
Solicitation of new data or corrections to existing data to revise emission standards calculations.
Exempting temporary boilers.
Clarifying the initial compliance schedule for existing boilers subject to tune-ups.
Defining periods of gas curtailment.
Providing an optional CO compliance mechanism using CEMS.
Averaging times for parameter monitoring. 
Providing an affirmative defense for malfunction events.
Adjusting frequency of tune-up work practices for very small units.
Selecting a 99 percent confidence interval for setting the CO emission limit.
Establishing GACT-based limits for biomass and oil-fired boilers.
Scope and duration of the energy assessment and deadline for completing the assessment.
Establishing GACT-based limits for PM at new oil-fired boilers.
Exempting area sources from title V permitting requirements.
In this action, the EPA is finalizing multiple changes to this standard after considering public comments on the items under reconsideration.
III. Summary of Final Action on Reconsideration
As stated above, the December 23, 2011, proposed rule addressed specific issues and provisions the EPA identified for reconsideration. This summary of the final rule reflects the agency's final action in regards to those provisions identified for reconsideration and on other discrete matters identified in response to comments or data received during the comment period. Information on other provisions and issues not proposed for reconsideration is contained in the notice and record for the 2011 final rule (76 FR 15554, March 21, 2011).
A. Affected Sources
      The final rule amends 40 CFR 63.11194 to clarify that an unaffected gas-fired boiler is a new affected source if, after March 21, 2014, the owner or operator commences fuel switching from natural gas to solid fossil fuel, biomass or liquid fuel and the boiler no longer meet the definition of a gas-fired boiler.
      We are also amending 40 CFR 63.11194 to clarify that a dual-fuel fired boiler meeting the definition of a gas-fired boiler can be classified as an existing affected oil-fired boiler and subject to all relevant requirements in the oil subcategory if a notification is submitted as an oil-fired boiler by January 20, 2014. A dual-fuel gas-fired boiler which notifies as an existing oil-fired boiler under 40 CFR 63.11194 and 63.11125 must comply with the requirements for existing oil-fired boilers by the applicable compliance dates for existing oil-fired boilers. Further, a gas and liquid fuel fired boiler which notifies as an existing oil-fired boiler must conduct the tune-up while burning the fuel which provided the majority of the heat input in the previous 12 months. 
B. Source Category Exclusions
This final rule amends the list of boilers excluded from the source category in 40 CFR 63.11195 to include certain boilers that may be located at an industrial, commercial or institutional area source facility. These clarifications of the source category are described below.
1. Electric Boilers.
The EPA is amending 40 CFR 63.11195 by adding electric boilers to the list of boilers not subject to subpart JJJJJJ. Electric boilers are defined in 40 CFR 63.11237 as follows:
      Electric boiler means a boiler in which electric heating serves as the source of heat. Electric boilers that burn gaseous or liquid fuel during periods of electrical power curtailment of failure are included in this definition.

2. Residential Boilers.
The EPA is amending 40 CFR 63.11195 by adding residential boilers to the list of boilers not subject to subpart JJJJJJ. We are clarifying that a residential boiler may be part of a residential combined heat and power system. Residential boilers are defined in 40 CFR 63.11237 as follows:
      Residential boiler means a boiler used in a dwelling containing four or fewer family units to provide heat and/or hot water and/or as part of a residential combined heat and power system. This definition includes boilers used primarily to provide heat and/or hot water for a dwelling containing four or fewer facilities located at an institutional facility (e.g., university campus, military base, church grounds) or commercial/industrial facility (e.g., farm).

3. Temporary Boilers. 
The EPA is amending 40 CFR 63.11195 by adding temporary boilers to the list of boilers not subject to subpart JJJJJJ. Similar to residential boilers, we did not intend to regulate temporary boilers under the area source standards because they are not part of either the industrial boiler source category or the commercial/institutional boiler source category. By their nature of being temporary, these boilers are operating in place of another non-temporary boiler while that boiler is being constructed, replaced or repaired, in which case we would have counted the non-temporary boiler as one being regulated. Additionally, the final major source rule for boilers excludes temporary boilers from the source category and we are now providing the same exclusion in the area source rule.
The definition of "temporary boiler" specifies that a boiler is not a temporary boiler if it remains at a location within the facility and performs the same or similar function for more than 12 consecutive months unless the regulatory agency approves an extension. Temporary boilers are defined in 40 CFR 63.11237 as follows:
      Temporary boiler means any gaseous or liquid fuel boiler that is designed to, and is capable of, being carried or moved from one location to another by means of, for example, wheels, skids, carrying handles, dollies, trailers, or platforms. A boiler is not a temporary boiler if any one of the following conditions exists:
      (1) The equipment is attached to a foundation.
      (2) The boiler or a replacement remains at a location within the facility and performs the same or similar function for more than 12 consecutive months, unless the regulatory agency approves an extension. An extension may be granted by the regulatory agency upon petition by the owner or operator of a unit specifying the basis for such a request. Any temporary boiler that replaces a temporary boiler at a location within the facility and performs the same or similar function will be included in calculating the consecutive time period.
      (3) The equipment is located at a seasonal facility and operates during the full annual operating period of the seasonal facility, remains at the facility for at least 2 years, and operates at that facility for at least 3 months each year.
      (4) The equipment is moved from one location to another within the facility in an attempt to circumvent the residence time requirements of this definition.

4. Boilers with Section 3005 Permits.
The EPA is clarifying the language in 40 CFR 63.11195(c) to provide an exclusion stating "unless such units do not combust hazardous waste and combust comparable fuels" such that it reads: "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), unless such units do not combust hazardous waste and combust comparable fuels."
5. Boilers used as Control Devices. 
The EPA is clarifying the language in 40 CFR 63.11195(g) to clarify that any boiler that is used as a control device to comply with a subpart under part 60, 61, or 65 of chapter 40 is not subject to subpart JJJJJJ 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.
C. Emission Limits
1. Hg Emission Limit for Coal-Fired Boilers.
The EPA is amending the Hg emission limit for coal-fired boilers to 0.000022 lb per MMBtu based on a revised analysis. The revised analysis excludes data for a utility boiler that was erroneously used as the basis for the Hg emission limit included in the March 2011 final rule. Further discussion of this revision to the Hg emission limit is located in the December 23, 2011, proposal (76 FR 80541).
2. Using the UPL for Setting CO Emission Limits. 
The EPA is amending the CO emission limit for coal-fired boilers to reflect a revised analysis that uses the original 99 percent confidence level in determining the UPL. We have also removed from our analysis the data from a boiler for which only two test runs were completed in measuring CO emissions. The required number of test runs for accurately measuring emissions and demonstrating compliance is three test runs. Therefore, we determined that the datum from this unit was not representative and we excluded it from the data set upon which we performed the revised analysis. Based on the results of the revised analysis, we are amending the CO emission limit for new and existing coal-fired boilers from 400 ppm by volume on a dry basis, corrected to 3 percent oxygen, to 420 ppm by volume on a dry basis, corrected to 3 percent oxygen.
D. Tune-up Work Practice and Management Practice Standards
1. Requirements for Seasonally Operated Boilers. 
The EPA is establishing separate requirements for a subcategory of boilers that are seasonally operated. For seasonally operated boilers, we are amending 40 CFR 63.11223 to specify that they are required to complete a tune-up every 5 years, instead of on a biennial basis as is required for most non-seasonal boilers. Specifically, existing seasonal boilers are required to complete the initial tune-up by March 21, 2014, and a subsequent tune-up every 5 years after the initial tune-up. New and reconstructed seasonal boilers are not required to complete an initial tune-up, but are required to complete a tune-up every 5 years after the initial startup of the new or reconstructed boiler. A combined total of 15 days of periodic testing of the seasonal boiler during the 7-month shutdown is allowed. The definition of "seasonal boiler" clarifies that it only applies to biomass- or oil-fired boilers. Seasonally operated boilers are defined in 40 CFR 63.11237 as follows:
      Seasonal boiler means a boiler that undergoes a shutdown for a period of at least 7 consecutive months (or 210 consecutive days) each 12-month period due to seasonal market conditions, except for periodic testing. Periodic testing shall not exceed a combined total of 15 days during the 7-month shutdown. This definition only applies to boilers that would otherwise be included in the biomass subcategory or the oil subcategory.
      
2. Requirements for Small Oil-Fired Units.
The EPA is establishing separate requirements for a subset of oil-fired boilers with a heat input capacity of equal to or less than 5 MMBtu/hr. We are amending 40 CFR 63.11223 to specify that this subset of small oil-fired boilers are required to complete a tune-up every 5 years, instead of on a biennial basis as is required for most larger oil-fired boilers. Specifically, existing oil-fired boilers with a heat input capacity of equal to or less than 5 MMBtu/hr are required to complete the initial tune-up by March 21, 2014, and a subsequent tune-up every 5 years after the initial tune-up. New and reconstructed oil-fired boilers with a heat input capacity of equal to or less than 5 MMBtu/hr are not required to complete an initial tune-up, but are required to complete a tune-up every 5 years after the initial startup of the new or reconstructed boiler.
3. Requirements for Boilers with Oxygen Trim Systems. 
The EPA is establishing separate requirements for boilers with oxygen trim systems that maintain an optimum air-to-fuel ratio. We are amending 40 CFR 63.11223 to specify that this subset of boilers are required to complete a tune-up every 5 years. Specifically, existing boilers with oxygen trim systems are required to complete the initial tune-up by March 21, 2014, and a subsequent tune-up every 5 years after the initial tune-up. New and reconstructed boilers with oxygen trim systems are not required to complete an initial tune-up, but are required to complete a tune-up every 5 years after the initial startup of the new or reconstructed boiler.
E. Energy Assessment Work Practice and Management Practice Standards
1. Scope.
The EPA is amending the definition of "energy assessment" to clarify that the scope of the energy assessment does not encompass energy use systems located off-site or energy use systems using electricity purchased from an off-site source. The energy assessment is limited to only those energy use systems, located on-site, associated with the affected boilers. We are also clarifying that the scope of the assessment is based on energy use by discrete segments of a facility and not by a total aggregation of all individual energy using segments of a facility.
The definition of "boiler system" is being revised in the final rule to clarify that it means the boiler and associated components directly connected to and serving the energy use systems. We are amending the definition of "energy use system" to clarify that energy use systems are only those systems using energy clearly produced by affected boilers. We are also revising the definition of "qualified energy assessor" such that the assessor is only required to have knowledge and capabilities specific to the processes at the facility and that the qualified energy assessor may be a company employee or an outside specialist.
We are clarifying that energy assessor approval and qualification requirements are waived in instances where past or amended energy assessments are used to meet the energy assessment requirements. Finally, we are specifying that a source operating under an energy management program developed according to the ENERGY STAR guideline for energy management, DOE Save Energy Now, or ISO 50001 compatible energy management systems, that includes the affected boilers, is allowed as an alternative to a one-time energy assessment.
2. Compliance Date. 
As specified in 40 CFR 63.11196(a)(3), existing boilers that are subject to the energy assessment requirement must achieve compliance with the energy assessment requirement no later than March 21, 2014. Thus, in order to meet the requirements of the rule, energy assessments must, therefore, be completed by the compliance date (March 21, 2014) for existing sources.
3. Maximum Duration Requirements. 
The EPA is amending the definition of "energy assessment" for facilities with affected boilers using less than 0.3 TBtu/yr and for facilities with affected boilers using 0.3 to 1 TBtu/yr to change the maximum time to conduct the energy assessment from one day to 8 on-site technical hours and from three days to 24 on-site technical hours, respectively, and to allow sources to perform longer assessments at their discretion. We are also amending the definition "energy assessment" for facilities with affected boilers using greater than 1 TBtu/yr to specify that the maximum time to conduct the assessment is up to 24 on-site technical hours for the first TBtu/yr plus 8 on-site technical hours for every additional 1.0 TBtu/yr not to exceed 160 on-site technical hours, but may be longer at the discretion of the owner or operator.
F. GACT-Based Standards
1. Establishing GACT-Based Emission Limits for Biomass and Oil-Fired Boilers. 
The EPA is not amending the GACT-based standards, as specified in the March 21, 2011, final rule, for biomass- and oil-fired boilers. Specifically, the final standards for biomass- and oil-fired area source boilers are based on GACT instead of based on MACT as were the proposed standards. Our rationale for the changes between proposal and promulgation for the biomass- and oil-fired boilers can be found in the preamble to the promulgated area source standards (76 FR 15565-15567 and 15574-15575, March 21, 2011). The final standards for area source biomass- and oil-fired boilers require these boilers to meet the following standards:
New boilers with heat input capacity greater than 10 MMBtu/hr that are biomass-fired or oil-fired must meet GACT-based numerical emission limits for PM.
New boilers with heat input capacity greater than 10 MMBtu/hr that are biomass-fired or oil-fired must comply with work practice standards to minimize the boiler's startup and shutdown periods following the manufacturer's recommendations, or the manufacturer's recommendations for a unit of similar design. 
Existing boilers with heat input capacity greater than 10 MMBtu/hr that are biomass-fired or oil-fired must have a one-time energy assessment performed by a qualified energy assessor or must have an energy management plan under which the owner or operator currently operates. 
All new and existing units, regardless of size, that are biomass-fired or oil-fired must have a GACT-based periodic tune-up. 
2. Setting GACT-Based PM Standards for New Oil-Fired Boilers. 
The EPA is not making any changes to the PM limit for new oil-fired boilers. New oil-fired boilers with heat input capacity greater than 10 MMBtu/hr must meet a GACT-based numerical emission limit for PM (0.03 pounds (lb) per MMBtu of heat input). New oil-fired units, regardless of size, must have a GACT-based periodic tune-up. Our rationale for finalizing GACT-based PM emissions limits can be found in the preamble to the promulgated area source standards (76 FR 15574, March 21, 2011).
G. Initial Compliance
1. Demonstrating Initial Compliance. 
The EPA is amending 40 CFR 63.11210 to clarify the dates by which new and reconstructed boilers need to demonstrate initial compliance. We are amending 40 CFR 63.11210(d) to clarify that only boilers that are subject to emission limits for PM, Hg or CO in Table 1 to subpart JJJJJJ have a 180-day period after the applicable compliance date to demonstrate initial compliance. We are adding a new paragraph (e) to clarify that boilers that are only subject to work practice standards, emission reduction measures, and management practices in Table 2 to subpart JJJJJJ, and not subject to emission limits in Table 1, must demonstrate initial compliance no later than the applicable compliance date.
We are also adding a new paragraph (g) to clarify that boilers that switch fuels that result in the applicability of a different subcategory must demonstrate initial compliance with the applicable standards of the new subcategory no later than 180 days after the date upon which the fuel switch is commenced as identified in the notification submitted according to 40 CFR 63.11225(g).
2. Schedule for Existing Boilers Subject to Tune-up Requirements. 
The EPA is amending 40 CFR 63.11196 to specify that all existing boilers subject to the tune-up requirement would have 3 years (by March 21, 2014) in which to demonstrate initial compliance, instead of 1 year as specified in the 2011 final rule (76 FR 15554, March 21, 2011) or 2 years as specified in the proposed reconsideration of final rule action (76 FR 80532, December 23, 2011). In the December 23, 2011, proposal, we specifically requested comment on whether the initial compliance period for the tune-up requirement should be extended to 3 years.
3. Conducting Initial Tune-ups at New and Reconstructed Sources. 
The EPA is removing the requirement for an initial tune-up for new and reconstructed boilers. Thus, new and reconstructed units are required to complete the applicable biennial or 5-year tune-up no later than 25 months or 61 months, respectively, after the initial startup of the new or reconstructed boiler.
4. Fuel Requirements. 
The EPA is amending 40 CFR 63.11223(b) to specify that boiler tune-ups must be conducted while burning the type of fuel that provided the majority of the heat input to the boiler over the 12 months prior to the tune-up.
H. Operating Limits
1. Operating Limits for Oxygen Concentration. 
The EPA is clarifying that the oxygen concentration must be at or above the minimum established during a performance stack test. These limits have also been clarified to be applicable when the unit is firing the fuel or fuel mixture utilized during the CO performance test.
2. Maximum Operating Load. 
The EPA is including provisions for establishing a unit-specific limit for maximum operating load that apply to any boiler subject to an emission limit for which compliance is demonstrated by a performance stack test. Operating load data includes fuel feed rate data or steam generation rate data.
3. Establishing Operating Limits for Wet Scrubbers. 
The EPA is amending the operating limit provisions in 40 CFR 63.11211(b)(2) for an ESP operated with a wet scrubber to remove the statement that the operating limits for ESP do not apply to dry ESP systems operated without a wet scrubber.
I. Continuous Compliance
1. CO Emission Limit.
The rule requires sources subject to a CO emission limit to demonstrate compliance by measuring CO emissions while also monitoring the oxygen content of the exhaust. We are amending the monitoring requirements in 40 CFR 63.11224(a) to allow sources subject to a CO emission limit the option to install, operate, and maintain a CO and oxygen CEMS. The CEMS must be installed, operated and maintained according to Performance Specifications 3 and 4A at 40 CFR part 60, appendix B, and according to the site-specific monitoring plan that each facility is required to develop. The CEMS will also be required to complete a performance evaluation, also according to Performance Specifications 3 and 4A. 
Sources have the option to demonstrate continuous compliance by monitoring both CO and oxygen using a CEMS to demonstrate compliance with the CO emission limit, corrected to 3 percent oxygen, or monitoring and complying with an oxygen content operating limit that is established during the performance stack test. Sources that use a CO and oxygen CEMS are exempt from initial CO performance testing and oxygen content operating limit requirements. Sources that choose to demonstrate continuous compliance by monitoring and complying with an oxygen content operating limit must install, operate, and maintain an oxygen analyzer system with the oxygen level set at or above the minimum percent oxygen by volume that is established as the operating limit for oxygen when firing the fuel or fuel mixture utilized during the most recent CO performance stack test. We have removed the requirement that the oxygen monitor be located at the outlet of the boiler, so that it can be located either within the combustion zone or at the outlet as a flue gas oxygen monitor.
We are amending the oxygen monitoring requirements to allow for the use of oxygen trim systems and have included oxygen trim systems in the definition of "oxygen analyzer system." We have clarified that operation of oxygen trim systems to meet the oxygen monitoring requirements shall not be done in a manner that compromises furnace safety. The definitions of "oxygen analyzer system" and "oxygen trim system" in 40 CFR 63.11237 read as follows:
Oxygen analyzer system means all equipment required to determine the oxygen content of a gas stream and used to monitor oxygen in the boiler flue gas, boiler firebox, or other appropriate intermediate location. This definition includes oxygen trim systems. The source owner or operator must install, calibrate, maintain, and operate the oxygen analyzer system in accordance with the manufacturer's recommendations.
Oxygen trim system means a system of monitors that is used to maintain excess air at the desired level in a combustion device. A typical system consists of a flue gas oxygen and/or carbon monoxide monitor that automatically provides a feedback signal to the combustion air controller.
2. Tune-up Standards. 
The EPA is amending the requirements for demonstrating continuous compliance with the work practice and management practice tune-up standards in 40 CFR 63.11223 to clarify that CO measurements that are required before and after tune-up adjustments may be taken using a portable CO analyzer. We are clarifying that the requirement to inspect the system controlling the air-to-fuel ratio may be delayed until the next scheduled shutdown, but must be inspected at least once every 36 months.
3. Performance Testing Frequency.
The EPA is amending 40 CFR 63.11220(b) to specify that the owner or operator of an affected oil-fired boiler does not need to conduct further PM emissions testing if, when demonstrating initial compliance with the PM emission limit, the performance test results show that the PM emissions are equal to or less than half of the PM emission limit. The owner or operator must continue to comply with all applicable operating limits and monitoring requirements.
If the initial performance test results show that the PM emissions are greater than half of the PM emission limit, the owner or operator must conduct subsequent performance tests as specified in 40 CFR 63.11220(a).
4. Fuel Analysis. 
The EPA is amending 40 CFR 63.11220(c) to specify that the owner or operator does not need to conduct further fuel analysis sampling if, when demonstrating initial compliance with the Hg emission limit, the Hg constituents in the fuel or fuel mixture are measured to be equal to or less than half of the Hg emission limit. The owner or operator must continue to comply with all applicable operating limits and monitoring requirements.
When demonstrating initial compliance with the Hg emission limit, if the Hg constituents in the fuel or fuel mixture are greater than half of the Hg emission limit, the owner or operator must conduct quarterly sampling.
5. Averaging Times. 
The EPA is amending the averaging time for parameter monitoring and compliance with operating limits to a 30-day rolling average.
The EPA is revising the definitions of "30-day rolling average" and "daily block average" to exclude periods of startup and shutdown or downtime in the calculation of the arithmetic mean.
6. Monitoring Data. 
The EPA is clarifying in 40 CFR 63.11221 the monitoring data collection requirements and the meaning of a "deviation" with respect to collecting monitoring data.
J. Periods of Startup, Shutdown and Malfunction
We are not changing the malfunction provisions in the March 2011 final rule.
1. Definitions. 
The EPA is revising the definitions of "startup" and "shutdown" such that they are tailored for industrial boilers and are consistent with the definitions of "startup" and "shutdown" in the 40 CFR part 63, subpart A General Provisions. The revised definitions reflect the fact that industrial boilers function to provide steam or, in the case of cogeneration units, electricity, and, thus, should be considered to be operating normally at all times steam of the proper pressure, temperature, and flow rate is being provided for use as process steam or for the cogeneration of electricity.
2. Compliance with Operating Limits. 
The EPA has clarified that operating limits must be met at all times except during periods of startup and shutdown.
3. Minimization of Startup and Shutdown Periods. 
The EPA is amending 40 CFR 63.11223(e) to include biomass- and oil-fired boilers in the requirement to minimize the time spent in startup and shutdown periods.
4. Affirmative Defense Language. 
In this final rule, the EPA is updating the affirmative defense provisions for malfunctions that were included in the March 21, 2011 final rule.
K. Notification, Recordkeeping and Reporting Requirements
The EPA is amending 40 CFR 63.11225(c)(2) to specify that records of fuel use and type are required only for boilers that are subject to numerical emission limits. We are also amending 40 CFR 63.11223(b) to clarify that the type and amount of fuel needs to be included in reports only if the boiler was physically and legally capable of using more than one type of fuel during that time period. Finally, we are specifying that for units sharing a fuel meter, the fuel use by each boiler may be estimated.
The EPA is amending 40 CFR 63.11225(b) to clarify the requirements for submitting a biennial or 5-year report for units that are only subject to tune-up requirements and to specify the information that must be included in the annual, biennial, or 5-year compliance report.
We are amending 40 CFR 63.11225(c)(2) to specify that a copy of the energy assessment and records documenting the days of operation for each boiler that meets the definition of a seasonal boiler must be maintained. We are also amending 40 CFR 63.11214(c) to remove the requirement for submitting, upon request, the energy assessment.
We are revising 40 CFR 63.11225(d) to remove the requirement that the most recent 2 years of records be maintained on site and are adding language that allows for computer access or other means of immediate access of records stored in a centralized location.
We are revising 40 CFR 63.11225(g) to add any physical change that may result in the applicability of a different subcategory to the notification requirement. We are also revising 40 CFR 63.11225(g) to specify that the notification must be provided within 30 days of switching fuels or making a physical change that resulted in the applicability of a different subcategory or a switch out of subpart JJJJJJ.
L. Title V Permitting Requirements
      For the reasons stated in our March 21, 2011, final rule (76 FR 15554) as well as our reconsideration proposal (76 FR 80532, December 23, 2011), the EPA is not making any changes to the title V exemption for natural and synthetic area sources. Thus, no area sources subject to subpart JJJJJJ are required to obtain a title V permit as a result of being subject to subpart JJJJJJ.
      Facilities that are synthetic area sources for HAP under subpart JJJJJJ may already be covered by a title V permit or may be required to obtain a title V permit in the future. For example, area source boilers could be major sources of non-HAP pollutants or could be located at sources that are subject to title V. Thus, the title V exemption in subpart JJJJJJ does not affect whether or not these area sources under subpart JJJJJJ are otherwise required to obtain a permit under part 70 or part 71.  See 40 CFR 70.3(a) and (b) or 71.3(a) and (b). 
Moreover, it is important to note that synthetic area sources under subpart JJJJJJ could be subject to more stringent permitting and monitoring requirements than natural area sources if federally-enforceable controls are applied in order for the source to become a synthetic area source.
M. Definition of Period of Gas Curtailment or Supply Interruption
We are amending the definition of "period of natural gas curtailment or supply interruption" in 40 CFR 63.11237 to clarify that a curtailment does not include normal market fluctuations in the price of gas that are not associated with periods of supplier delivery restrictions. We are also amending the definition to indicate that periods of supply interruption that are beyond control of the facility can also include on-site natural gas system emergencies and equipment failures, and that legitimate periods of supply interruption are not limited to off-site circumstances. We are revising the term and the definition so that it includes the curtailment of any gaseous fuel, and is not limited to just natural gas. Finally, we are clarifying that the supply of gaseous fuel is to an "affected boiler" rather than "affected facility" and that the supply of gaseous fuel is "restricted" rather than "halted" for reasons beyond the control of the facility. The definition is amended to read as follows:
      Period of gas curtailment or supply interruption means a period of time during which the supply of gaseous fuel to an affected boiler is restricted for reasons beyond the control of the facility. The act of entering into a contractual agreement with a supplier of natural gas established for curtailment purposes does not constitute a reason that is under the control of a facility for the purposes of this definition. An increase in the cost or unit price of natural gas due to normal market fluctuations not during periods of supplier delivery restriction does not constitute a period of natural gas curtailment or supply interruption. On-site gaseous fuel system emergencies or equipment failures may qualify as periods of supply interruption when the emergency or failure is beyond the control of the facility.

N. Other Miscellaneous Technical Corrections
In addition to the above summary of the EPA's final action regarding provisions identified for reconsideration and on other discrete matters identified in response to comments or data received during the comment period, other definitional and regulatory text revisions are being made. These clarifications will help affected sources determine their applicability and better understand the rule requirements. In some instances, definitions and regulatory text have been revised or added to correspond with other related rules, especially the emission standards for industrial, commercial, and institutional boilers at major sources of HAP (40 CFR part 63, subpart DDDDD. Section IV of this preamble includes additional details regarding these miscellaneous technical corrections.
IV. Summary of Significant Changes Since Proposed Action on Reconsideration 
Numerous changes are being made to the final rule based on the public comments received. Most are editorial changes to clarify applicability and implementation issues raised by the commenters. The public comments received on the proposed changes and the responses to them can be viewed in the memorandum "Response to Comments for Industrial, Commercial, and Institutional Area Source Boilers National Emission Standards for Hazardous Air Pollutants" located in the docket.
A. Applicability
Since proposal, changes to the applicability of this final rule have been made.
1. Dual-Fuel Fired Boilers.
      The March 2011 final rule includes as a new affected source a boiler that commences fuel switching from natural gas to solid fossil fuel, biomass, or liquid fuel after June 4, 2010. For example, if an unaffected gas-fired boiler currently burns oil as allowed under the definition of gas-fired boiler, but after June 4, 2010 burns oil for reasons not allowed under the definition of gas-fired, these boilers would become new affected units under 40 CFR 63.11194(d), and must meet the compliance dates as specified in 40 CFR 63.11196(b) and (c) for new affected oil-fired boilers. The EPA has been made aware that many dual-fuel fired units presently burn primarily natural gas with limited or no amounts of oil, but these units may want to burn oil in the future for reasons not allowed under subpart JJJJJJ's definition of gas-fired (e.g. cost). We know of at least one state agency that has provided written guidance that an existing dual fuel gas-fired boiler that wants to avoid being subject to the new source requirements should notify as an existing oil-fired unit. We agree that this is the EPA's intent. The EPA's intent with respect to compliance requirements in these instances, however, was not clear in the 2011 final rule. In at least one instance, the guidance provided was that these units are not required to comply with the oil-fired subcategory provisions of the rule until they start burning oil for reasons not allowed under the definition of gas-fired. This does not reflect the EPA's intent. As a result of this lack of clarity, one EPA regional office is receiving revised notifications from sources that are requesting to retract their initial notification and now notify as existing oil-fired units. In this final rule, the EPA is providing clarification of compliance requirements for these dual fuel fired boilers.
      Because the March 2011 final rule does not make it clear that we intend fuel switching to include the situation where a dual-fuel fired (oil and gas) boiler switches from being an unaffected gas-fired boiler to an affected oil-fired boiler, we are amending the rule to allow these sources until the initial compliance date to switch fuels and still be considered an existing boiler. In this final rule, we are also clarifying the fuel switching notification requirements in the rule. Specifically, this final rule amends 40 CFR 63.11194 to clarify that an unaffected gas-fired boiler is a new affected source if, after March 21, 2014, the owner or operator commences fuel switching from natural gas to solid fossil fuel, biomass or liquid fuel and the boiler no longer meet the definition of a gas-fired boiler. We are also amending 40 CFR 63.11194 to clarify that a dual-fuel fired boiler meeting the definition of a gas-fired boiler can be classified as an existing affected oil-fired boiler and subject to all relevant requirements in the oil subcategory if a notification is submitted as an oil-fired boiler by January 20, 2014 (60 days prior to the March 21, 2014 compliance date). A dual-fuel gas-fired boiler which notifies as an existing oil-fired boiler under 40 CFR 63.11194 and 63.11125 must comply with the requirements for existing oil-fired boilers as specified in 40 CFR 63.11196 by the applicable compliance dates for existing oil-fired boilers. Further, a gas and liquid fuel fired boiler which notifies as an existing oil-fired boiler must conduct the tune-up while burning the fuel which provided the majority of the heat input in the previous 12 months as specified in 40 CFR 63.11223(a).
2. Residential Boilers. 
One commenter suggested that the definition of "residential boiler" be revised to acknowledge the use of combined heat and power systems which function with heat and/or hot water systems. The EPA agrees and is amending the definition in the final rule to clarify that a boiler that operates as part of a residential combined heat and power system (and that meets other definitional requirements) is a residential boiler.
3. Temporary Boilers. 
One commenter supported the EPA's 12-month threshold above which the boiler would no longer be considered temporary but pointed out that a boiler used on a temporary basis during construction of a commercial building may be needed for more than 12 months due to the length of the construction period. The commenter suggested that the definition of temporary boiler be revised to allow owners or operators to petition for an extension beyond 12 months. We agree with the commenter and are amending the definition in the final rule to allow an owner or operator to submit to their regulatory agency a petition for an extension beyond 12 months. Another commenter suggested that the EPA expand on the intent of "location" in the definition of "temporary boiler. We are amending the definition to clarify that "location" means "location within the facility."
4. Seasonal Boilers. 
Several commenters explained that boilers subject to semi-annual testing requirements would not meet the proposed 7 consecutive month shutdown criteria, but otherwise would be considered seasonal boilers. Commenters suggested that seasonal boiler be defined to allow periodic testing during the 7-month shutdown period. We agree with the commenters and are revising the definition of seasonal boiler in the final rule to allow for a combined total of 15 days of use during the shutdown period for periodic testing.
Another commenter pointed out that the EPA's seasonal boiler definition, as proposed, would potentially allow more regular use. The commenter specifically suggested that the definition be revised to clarify that there must be a 7 consecutive month shutdown every 12 months. It was the EPA's intent that the shutdown period of at least 7 consecutive months be on a 12-month basis. In response to this comment, we are clarifying in the definition of seasonal boiler that the shutdown must be for a period of at least 7 consecutive months (or 210 consecutive days) each 12-month period.
B. Tune-Up Requirements 
1. Boilers with Oxygen Trim Systems.
In the final rule, the EPA is adding to the types of boilers that must conduct a tune-up every 5 years boilers that have an oxygen trim system that maintain an optimum air-to-fuel ratio. These units do not need to be tuned as frequently as other types of boilers because the trim system is designed to maintain an optimum air to fuel ratio which is the purpose of a tune-up.
2. Initial Compliance for Existing Boilers. 
The EPA is revising the initial compliance date for existing boilers subject to the work practice or management practice standard of a tune-up. Under the proposed rule, owners and operators of existing affected boilers would have had to comply with the final rule by March 21, 2013. We also solicited comments on whether to extend the compliance date to March 21, 2014. We received no comments objecting to either of these dates. Support for an extension until 2014 came from a variety of stakeholders affected by the rule. Therefore, the final rule requires that if you own or operate an existing boiler subject to a work practice or management practice standard of a tune-up, you must comply with the final rule no later than March 21, 2014.
C. Energy Assessment
The EPA received a number of comments regarding the energy assessment requirements and in the final rule is making a series of changes to the energy assessment provisions and related definitions that clarify terms used and better set the scope of the assessment.
In the final rule, we are revising the definition of energy assessment by providing a duration for performing the energy assessment for numbered paragraph (3) in the definition of "energy assessment" in 40 CFR 63.11237 for facilities with units using greater than 1 TBtu/yr to specify time duration/size ratio and are including a cap to the maximum number of on-site technical hours that should be used in the energy assessment. The energy assessment for facilities with affected boilers and process heaters using greater than 1.0 TBtu/yr will be up to 24 on-site technical labor hours in length for the first TBtu/yr plus 8 technical labor hours for every additional 1.0 TBtu/yr not to exceed 160 technical hours, but may be longer at the discretion of the owner or operator.
The revised definition of energy assessment also clarifies our intentions that the scope of assessment is based on energy use by discrete segments of a facility and not by a total aggregation of all individual energy using elements of a facility. The applicable discrete segments of a facility could vary significantly depending on the site and its complexity. We are adding the following language, as paragraph (4), to the "energy assessment" definition to help resolve current problems and allow for more streamlined assessments:
"(4) The on-site energy use systems serving as the basis for the percent of affected boiler(s) energy output in (1), (2), and (3) above may be segmented by production area or energy use area as most logical and applicable to the specific facility being assessed (e.g., product X manufacturing area; product Y drying area; Building Z)."
We are revising 40 CFR 63.11201 and Table 2 of the final rule to allow a source that is operating under an energy management program developed according to the ENERGY STAR guideline for energy management, DOE Save Energy Now, or ISO 50001 compatible energy management systems, that includes the affected units, to satisfy the energy assessment requirement. In addition, we are clarifying that energy assessor approval and qualification requirements are waived in instances where past or amended energy assessments are used to meet the energy assessment requirements.
The definition of "boiler system" is being revised in the final rule to clarify that it means the boiler and associated components directly connected to and serving the energy use systems.
The definition of "energy use system" is also being revised in the final rule to clarify that energy use systems are only those on-site systems using energy clearly produced by affected boilers. 
The definition of "qualified energy assessor" is being revised in the final rule to be more general such that the assessor is only required to have knowledge and capabilities specific to the processes at the site and, to clarify, that qualified energy assessors may be company employees or outside specialists.
D. Clarification of Oxygen Concentration Operating Limits
We are clarifying in the final rule that operating limits for oxygen concentration must be at or above the minimum established during a performance stack test. We are also clarifying that these limits are applicable when the unit is firing the fuel or fuel mixture utilized during the CO performance test.
E. Definitions Regarding Averaging Times
The EPA received comments requesting that we clarify that periods of startup and shutdown are excluded from calculation of the arithmetic mean in the definitions of "30-day rolling average" and "daily block average." We agree with the commenters and are revising the definitions in the final rule accordingly.
F. Continuous Compliance
We solicited comment on the requirements for demonstrating continuous compliance with the work practice and management practice tune-up standards, with one focus on clarifying how to measure CO. Commenters requested that we clarify that CO measurements may be taken with a portable CO analyzer. We agree that this clarification is appropriate and are including this clarification in the final rule.
G. Fuel Sampling Frequency
The EPA is amending the fuel sampling requirements in 40 CFR 63.11220(c) because we realized that when performance stack testing requirements were revised in the March 2011 final rule we neglected to revise the fuel analysis requirements. In the final rule, we are specifying that the owner or operator does not need to conduct further fuel analysis sampling if, when demonstrating initial compliance with the Hg emission limit, the Hg constituents in the fuel or fuel mixture are measured to be equal to or less than half of the Hg emission limit. If, when demonstrating initial compliance, the Hg constituents in the fuel or fuel mixture are greater than half of the Hg emission limit, the owner or operator must conduct quarterly sampling.
H. Performance Testing Frequency.
The EPA is amending the PM performance testing requirements in 40 CFR 63.11220(b) to specify that the owner or operator of an affected oil-fired boiler does not need to conduct further PM emission testing if, when demonstrating initial compliance with the PM emission limit, the performance test results show that the PM emissions are equal to or less than half of the PM emission limit. The owner or operator must continue to comply with all applicable operating limits and monitoring requirements. If the initial performance test results show that the PM emissions are greater than half of the PM emission limit, the owner or operator must conduct subsequent performance tests as specified in 40 CFR 63.11220(a).
With respect to the reconsideration issue regarding the GACT-based PM standards for new oil-fired boilers, we received comments asserting that the most effective control strategy for small oil-fired boilers is the tune-up required by the standards and that establishing a PM limit for those boilers between 10 MMBtu/hr and 30 MMBtu/hr just ensures that those boilers will do stack testing demonstrating that the boilers are in compliance without the need for controls; a fact already known. Commenters also asserted that establishing a PM limit imposes a stack test obligation on small facilities with the least resources to deal with the testing.
We have reviewed the comments and are not eliminating or revising the PM limit for new oil-fired boilers with heat input capacity between 10 MMBtu/hr and 30 MMBtu/hr. We do, however, believe that adjustments to the PM performance test frequency as described above are appropriate for oil-fired boilers that demonstrate during their initial performance test that their PM emissions are equal to or less than half of the PM limit. Owners or operators of oil-fired boilers whose initial performance test results show that their PM emissions are equal to or less than half of the PM emission limit and, thus, do not need to conduct further PM emissions testing, must continue to comply with all applicable operating limits and monitoring requirements to ensure that there are no changes in operation of the boiler or air pollution control equipment that could increase emissions. This adjustment in PM performance test frequency will potentially reduce the burden on small entities operating oil-fired boilers that meet the adjustment criteria. 
I. Startup and Shutdown Definitions
A number of commenters indicated that the proposed load specifications (i.e., 25 percent load) within the definitions of "startup" and "shutdown" were inconsistent with either safe or normal (proper) operation of the various types of boilers encountered within the source category. As the basis for defining periods of startup and shutdown, a number of commenters suggested alternative load specifications based on the specific considerations of their boilers; other commenters suggested the achievement of various steady-state conditions.
We have reviewed these comments and believe adjustments are appropriate in the definition of "startup" and "shutdown." These adjustments are tailored for industrial boilers and are consistent with the definitions of "startup" and "shutdown" contained in the 40 CFR part 63, subpart A General Provisions. We believe these revised definitions address the comments and are rational based on the fact that industrial boilers function to provide steam or, in the case of cogeneration units, electricity; therefore, industrial boilers should be considered to be operating normally at all times steam of the proper pressure, temperature and flow rate is being provided to a common header system or energy user(s) for use as either process steam or for the cogeneration of electricity. The definitions of "startup" and "shutdown" have been revised in the final rule as follows:
      Startup means either the first-ever firing of fuel in a boiler for the purpose of supplying steam or heat for heating and/or producing electricity, or for any other purpose, or the firing of fuel in a boiler after a shutdown event for any purpose. Startup ends when any of the steam or heat from the boiler is supplied for heating and/or producing electricity, or for any other purpose.
      
      Shutdown means the cessation of operation of a boiler for any purpose. Shutdown begins either when none of the steam or heat from the boiler is supplied for heating and/or producing electricity, or for any other purpose, or at the point of no fuel being fired in the boiler, whichever is earlier. Shutdown ends when there is both no steam or heat being supplied and no fuel being fired in the boiler.

J. Notification of Fuel Change or Physical Change
The notification requirement in 40 CFR 63.11225(g) of the final rule for instances when a change in fuel or a physical change to a boiler results in the applicability of a different subcategory or a change out of subpart JJJJJJ is being revised. Under the proposed reconsideration action, a facility would have been required to provide 30 days prior notice of the date upon which the change was scheduled to occur. Commenters explained that an advanced notification requirement would delay such a change if the owner or operator decided to immediately make a change (e.g., switch to 100 percent natural gas) and could potentially restrict flexibility in manufacturing operations, and suggested that the owner or operator be allowed to make notification within 30 days after the change has occurred. We agree that notification within 30 days after a change that results in applicability of a different subcategory or a change out of subpart JJJJJJ will provide the EPA or state/local agency with the required information within a reasonable timeframe. Thus, in the final rule, we are requiring facilities making these types of changes to provide notification within 30 days following the change.
K. Miscellaneous Definitions
In the final action, we are clarifying a number of definitions to help affected sources determine their applicability. In some cases, definitions have been revised or added to correspond with those used elsewhere in related rules. Specifically, definitions have been added for the terms "30-day rolling average," "Biodiesel," "Calendar year," "Daily block average," "Distillate oil," "Electric boiler," "Electric utility steam generating unit (EGU)," "Energy management program," "Load fraction," "Minimum scrubber pressure drop," "Minimum sorbent injection rate," "Minimum total secondary electric power," "Operating day," "Oxygen analyzer system," "Oxygen trim system," "Process heater," "Residential boiler," "Residual oil," "Seasonal boiler," "Shutdown," "Startup," "Solid fuel," "Temporary boiler," "Tune-up," "Vegetable oil," and "Wet scrubber."
Definitions revised to clarify the term include "Annual heat input basis," "Bag leak detection system," "Biomass subcategory," "Boiler," "Boiler system," "Deviation," "Dry scrubber," "Energy assessment," "Energy use system," "Federally enforceable," "Gas-fired boiler," "Heat input," "Hot water heater," "Institutional boiler," "Minimum activated carbon injection rate," "Minimum scrubber liquid flow rate," "Natural gas," "Oil subcategory," "Period of natural gas curtailment or supply interruption," "Qualified Energy Assessor," and "Waste heat boiler."
V. Other Actions the EPA is Taking
Section 307(d)(7)(B) of the CAA states that "[o]nly an objection to a rule or procedure which was raised with reasonable specificity during the period for public comment (including any public hearing) may be raised during judicial review. If the person raising an objection can demonstrate to the Administrator that it was impracticable to raise such objection within such time 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, the Administrator shall convene a proceeding for reconsideration of the rule and provide the same procedural rights as would have been afforded had the information been available at the time the rule was proposed. If the Administrator refuses to convene such a proceeding, such person may seek review of such refusal in the United States court of appeals for the appropriate circuit (as provided in subsection (b))."
As to the first procedural criterion for reconsideration, a petitioner must show why the issue could not have been presented during the comment period, either because it was impracticable to raise the issue during that time or because the grounds for the issue arose after the period for public comment (but within 60 days of publication of the final action). The EPA is denying the petitions for reconsideration on a number of issues because this criterion has not been met. In many cases, the petitions reiterate comments made on the proposed June 2011 rule during the public comment period for that rule. On those issues, the EPA responded to those comments in the final rule, and made appropriate revisions to the proposed rule after consideration of public comments received. It is well established that an agency may refine its proposed approach without providing an additional opportunity for public comment. See Community Nutrition Institute v. Block, 749 F.2d 50, 58 (D.C. Cir. 1984) and International Fabricare Institute v. EPA, 972 F.2d 384, 399 (D.C. Cir. 1992) (notice and comment is not intended to result in "interminable back-and-forth[,]" nor is agency required to provide additional opportunity to comment on its response to comments) and Small Refiner Lead Phase-Down Task Force v. EPA, 705 F.2d 506, 547 (D.C. Cir. 1983) ("notice requirement should not force an agency endlessly to repropose a rule because of minor changes")
In the EPA's view, an objection is of central relevance to the outcome of the rule only if it provides substantial support for the argument that the promulgated regulation should be revised. See Union Oil v. EPA, 821 F.2d 768, 683 (D.C. Cir. 1987) (court declined to remand rule because petitioners failed to show substantial likelihood that final rule would have been changed based on information in petition). See also the EPA's Denial of the Petitions to Reconsider the Endangerment and Cause or Contribute Findings for Greenhouse Gases under Section 202 of the Clean Air Act, 75 FR at 49556, 49561 (August 13, 2010). See also, 75 FR at 49556, 49560 - 49563 (August 13, 2010) and 76 FR at 4780, 4786 - 4788 (January 26, 2011) for additional discussion of the standard for reconsideration under CAA section 307(d)(7)(B).
We are denying reconsideration on the following five issues contained in the petitions for reconsideration because they failed to meet the standard described above for reconsideration under CAA section 307(d)(7)(B). Specifically, on these issues, the petitioner has failed to show the following: That it was impracticable to raise their objections during the comment period or that the grounds for their objections arose after the close of the comment period; and/or that their concern is of central relevance to the outcome of the rule. Therefore, the EPA is denying the petitions for reconsideration on the issues for the reasons described below.
Issue: Use of RDL is Unlawful.
The petitioner (Sierra Club) objected to the EPA establishing a MACT floor emission limit at a level equal to three times the RDL as being unlawful and arbitrary. This issue is not of central relevance to the outcome of this final rule. The final emission limits in this rule are based on the UPL at a confidence interval of 99 percent. The RDL analysis was not used in this final rule.
Issue: MACT Floor for Existing Sources Must Reflect Average Performance of the Top 12 Percent of Units.
The petitioner (Sierra Club) stated that the MACT floor for existing sources must reflect the average performance of the top 12 percent of units. The petitioner has not demonstrated that it lacked the opportunity to comment on the EPA's MACT floor analysis. The methods used to compute the MACT floors were subject to notice and comment. Rationale and responses to comments on the MACT floor methodology were provided at 75 FR 31904, June 4, 2010; 76 FR 15571, March 21, 2011. Therefore, the EPA is denying the request for reconsideration.
Issue: Consider a de Minimis Size Threshold.
The petitioners (American Petroleum Institute, National Petrochemical and Refiners Association, Alaska Oil and Gas Association) requested that the EPA consider a de minimis size threshold using guidelines from insignificance thresholds authorized under CAA part 71. The EPA is denying the request for reconsideration on this issue. In the June 2010 proposed rule, it was readily apparent that we were not establishing de minimis size thresholds in the area source rulemaking. We received multiple comments on this issue and responded to them in the response to comments document for the March 2011 final rule. The issue on which petitioners seek reconsideration was one that could have been raised during the comment period and thus does not meet the requirements for reconsideration. Therefore, the EPA is denying this request for reconsideration.
Issue: MACT Standards Must be Set for all HAP.
The petitioner (Sierra Club) asserted that MACT standards must be set for all HAP including HAP not listed in CAA section 112(c)(6). The EPA is denying the request for reconsideration on this issue. We disagree with the petitioner that the EPA must issue emission standards for all HAP. MACT standards have been set for Hg and CO, as a surrogate for POM emissions, but the EPA does not interpret CAA section 112(c)(6) to compel regulation of all HAP emitted by area sources. The EPA's position on this issue was clear in the proposed rule [ADD CITE]. This commenter raised this issue in its comments (76 FR 15567, March 21, 2011). Not only did the petitioner have an opportunity to present its theory in its comments, but also it did so.
Issue: CO is not a valid surrogate for POM.
The petitioner (Sierra Club) requested that the EPA remove the CO standard as a surrogate for POM and instead adopt a numeric limit for POM because CO is not an appropriate surrogate. The EPA is denying the request for reconsideration on this issue. While the EPA disagrees with the petitioner's argument regarding the suitability of CO as a surrogate for POM, the petitioner has not demonstrated that it lacked the opportunity to comment on this issue. The EPA revised the final CO emission limit to ensure a more accurate correlation between POM and CO levels. The EPA made our position on this issue clear and explained the agency's basis for concluding that CO was an appropriate surrogate in the proposed rule (75 FR 31900, 31904, June 4, 2010). The petitioner raised this issue in its comments [ADD CITE]. Therefore, the EPA is denying the request for reconsideration.
VI. Impacts associated with this Final Rule
The amendments contained in this action are corrections that are intended to clarify, but not change, the coverage of the final rule. The clarifications and corrections should make it easier for owners and operators and for local and state authorities to understand and implement the requirements. The amendments will not increase the costs for the final rule but will result in a decrease in the burden on small facilities as a result of the reduction in the frequency of conducting tune-ups for seasonal boilers and small (equal to or less than 5 MMBtu/hr) oil-fired boilers. Additionally, the burden will be reduced on facilities that currently operate under an energy management program developed according to the ENERGY STAR guideline for energy management, DOE Save Energy Now, or ISO 50001 compatible energy management systems because a one-time energy assessment will not be required.
As discussed in section III, the Hg emission limits for new and existing large (10 MMBtu/hr or greater) coal-fired area source boilers were revised because of an error discovered in the analysis conducted for the final rule. This technical correction resulted in an increase in the emission limits for Hg. Concurrently, we revised our impacts analysis to be consistent with changes made to the major source boiler rule. The baseline emissions for area sources are calculated using the emission factors developed for the major source rule because of insufficient data for area sources. Since promulgation, the EPA has received and incorporated a significant amount of additional data and has corrected previous calculation errors that impacted the emission factors used to calculate baseline emissions resulting in a higher baseline emission for Hg from coal-fired area source boilers. Consequently, the result of the increase in both baseline Hg emissions and Hg emission limits in this action is that the overall reduction in Hg emissions does not change significantly from the estimated reduction for the promulgated rule.  
In summary, as compared to the control costs estimated in the March 2011 final rule, these amendments will result in a decrease in the capital and annual cost due to the increase in emission limits and the decrease in burden on small facilities.
VII. Statutory and Executive Order Reviews
A. Executive Order 12866: Regulatory Planning and Review and Executive Order 13563: Improving Regulation and Regulatory Review
Under section 3(f)(1) of Executive Order 12866 (58 FR 51735, October 4, 1993), this action is a "significant regulatory action" because it is likely to raise novel legal or policy issues. Accordingly, the EPA submitted this action to the OMB for review under Executive Order 12866 and Executive Order 13563 (76 FR 3821, January 21, 2011), and any changes made in response to OMB recommendations have been documented in the docket for this action.
B. Paperwork Reduction Act
This action does not impose an information collection burden. This action results in no significant changes to the information collection requirements of the promulgated rule and will have no increased impact on the information collection estimate of projected cost and hour burden made and approved by OMB. In fact, the reduction in tune-up frequency for some boilers will result in less information collection burden. Therefore, the information collection request has not been revised. However, the OMB has previously approved the information collection requirements contained in the existing regulation (40 CFR part 63, subpart JJJJJJ) under the provisions of the Paperwork Reduction Act, 44 U.S.C. 3501, et seq. and has assigned OMB control number 2060-0668. The OMB control numbers for the EPA's regulations in 40 CFR are listed in 40 CFR part 9.
C. Regulatory Flexibility Act
The RFA generally requires an agency to prepare a regulatory flexibility analysis of any rule subject to notice and comment rulemaking requirements under the Administrative Procedure Act or any other statute unless the agency certifies that the rule will not have a significant economic impact on a substantial number of small entities. The RFA also allows an agency to "consider a series of closely related rules as one rule for the purposes of sections" 603 (initial regulatory flexibility analysis) and 604 (final regulatory flexibility analysis) in order to avoid "duplicative action." 5 U.S.C. §605(c). These final amendments and notice of final action on reconsideration are closely related to the boiler area source rule, which the EPA signed on February 21, 2011, and that took effect on May 20, 2011. The EPA prepared a final regulatory flexibility analysis in connection with the boiler area source rule. Therefore, pursuant to §605(c), the EPA is not required to complete a final regulatory flexibility analysis for this rule (i.e., the amendments and final action).
The EPA has been concerned with potential small entity impacts since it began developing the boiler area source rule. The EPA conducted outreach to small entities and, pursuant to §609 of RFA, convened a Small Business Advocacy Review Panel (the Panel) on January 22, 2009, to obtain advice and recommendations from small entity representatives. Pursuant to the RFA, the EPA used the Panel's report and prepared both an initial regulatory flexibility analysis and a final regulatory flexibility analysis in connection with the closely related boiler area source rule. Convening an additional Panel and preparing an additional final regulatory flexibility analysis would be procedurally duplicative and is unnecessary given that the issues here are within the scope of those considered by the Panel. Finally, we note that this action, which amends the boiler area source rule, will not impose any additional regulatory requirements beyond those imposed by the previously promulgated boiler area source rule and, in fact, the amendments will afford relief to some boilers. 
D. Unfunded Mandates Reform Act
This action contains no new federal mandates under the provisions of Title II of the UMRA of 1995, 2 U.S.C. 1531-1538 for state, local, or tribal governments or the private sector. This action imposes no new enforceable duty on any state, local, or tribal governments or the private sector. Therefore, this action is not subject to the requirements of sections 202 and 205 of the UMRA.
This action is also not subject to the requirements of section 203 of UMRA because it contains no regulatory requirements that might significantly or uniquely affect small governments. This rule finalizes amendments to aid with compliance, but does not change the level of the standards in the rule. 
E. Executive Order 13132: Federalism
This action does not have federalism implications. It will not have substantial direct effects on the states, on the relationship between the national government and the states, or on the distribution of power and responsibilities among the various levels of government, as specified in Executive Order 13132. This final rule will not impose new direct compliance costs on State or local governments, and will not preempt State law. Thus, Executive Order 13132 does not apply to this action.
F. Executive Order 13175: Consultation and Coordination with Indian Tribal Governments
This final action does not have tribal implications, as specified in Executive Order 13175 (65 FR 67249, November 9, 2000). It will not have substantial new direct effects on tribal governments, on the relationship between the federal government and Indian tribes, or on the distribution of power and responsibilities between the Federal government and Indian tribes, as specified in Executive Order 13175. Thus, Executive Order 13175 does not apply to this action.
G. Executive Order 13045: Protection of Children from Environmental Health Risks and Safety Risks
The EPA interprets Executive Order 13045 (62 FR 19885, April 23, 1997) as applying to those regulatory actions that concern health or safety risks, such that the analysis required under section 5-501 of the Order has the potential to influence the regulation. This action is not subject to Executive Order 13045 because it is based solely on technology performance. 
H. Executive Order 13211: Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution, or Use
This 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. 
I. National Technology Transfer and Advancement Act
Section 12(d) of the NTTAA of 1995, Public Law No. 104-113, 12(d) (15 U.S.C. 272 note) directs the EPA to use VCS in its regulatory activities, unless to do so would be inconsistent with applicable law or otherwise impractical. VCS are technical standards (e.g., materials specifications, test methods, sampling procedures, and business practices) that are developed or adopted by VCS bodies. NTTAA directs the EPA to provide Congress, through OMB, explanations when the agency decides not use available and applicable VCS.
This action does not involve any new technical standards. Therefore, the EPA did not consider the use of any VCS.
J. Executive Order 12898: Federal Actions to Address Environmental Justice in Minority Populations and Low-Income Populations
Executive Order 12898 (59 FR 7629, February 16, 1994) establishes federal executive policy on environmental justice. Its main provision directs federal agencies, to the greatest extent practicable and permitted by law, to make environmental justice part of their mission by identifying and addressing, as appropriate, disproportionately high and adverse human health or environmental effects of their programs, policies, and activities on minority populations and low-income populations in the United States.
The EPA has determined that this final rule will not have disproportionately high and adverse human health or environmental effects on minority or low-income populations because the level of protection provided to human health or the environment through the rule's requirements does not vary. Therefore, it does not have any disproportionately high or adverse human health or environmental effects on any population, including any minority or low-income population.
K. Congressional Review Act
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 the rule must submit a rule report, which includes a copy of the rule, to each House of the Congress and to the Comptroller General of the United States. The 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 the rule in the Federal Register. A Major rule cannot take effect until 60 days after it is published in the Federal Register. Because this action makes small changes to the rule and does not revise the entire rule, this action is not a "major rule" as defined by 5 U.S.C. 804(2). This rule will be effective [INSERT THE DATE OF PUBLICATION IN THE FEDERAL REGISTER].

 List of Subjects in 40 CFR Part 63
       Environmental protection, Administrative practice and procedure, Air pollution control, Hazardous substances.
 
 
 				
 Dated:
 
 
 
 					
 Lisa P. Jackson,
 Administrator. 

For the reasons stated in the preamble, title 40, chapter I, part 63 of the Code of Federal Regulations is amended as follows:
PART 63 -- -[AMENDED]
The authority citation for part 63 continues to read as follows:
	Authority: 42 U.S.C. 7401 et seq.
Subpart JJJJJJ-[AMENDED]
Section 63.11194 is amended by revising paragraphs (d) and (e) and adding paragraph (f) to read as follows:
 §63.11195 What is the affected source of this subpart?
*	*	*	*	*
      (d) An unaffected gas-fired boiler is a new affected source if, after March 21, 2014, you commenced fuel switching from natural gas to solid fossil fuel, biomass, or liquid fuel and no longer meet the definition of a gas-fired boiler.
 (e) A dual-fuel fired boiler meeting the definition of a gas-fired boiler can be classified as an existing affected oil-fired boiler and subject to all relevant requirements in the oil subcategory if a notification is submitted as an oil-fired boiler by January 20, 2014.
 (f) If you are an owner or operator of an area source subject to this subpart, you are exempt from the obligation to obtain a permit under 40 CFR part 70 or part 71 as a result of this subpart. You may, however, be required to obtain a title V permit due to another reason or reasons.  See 40 CFR 70.3(a) and (b) or 71.3(a) and (b).  Notwithstanding the exemption from title V permitting for area sources under this subpart, you must continue to comply with the provisions of this subpart.
Section 63.11195 is amended by revising the introductory text and paragraphs (c) and (g) and by adding paragraphs (h), (i), (j), and (k) to read as follows:
§63.11195 Are any boilers not subject to this subpart? 
The types of boilers listed in paragraphs (a) through (k) of this section are not subject to this subpart and to any requirements in this subpart.
*	*	*	*	*
(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), unless such units do not combust hazardous waste and combust comparable fuels.
*	*	*	*	*
(g) Any boiler that is used as a control device to comply with another subpart of this part, or part 60, part 61, or part 65 of this chapter 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.
(h) Temporary boilers as defined in this subpart.
(i) Residential boilers as defined in this subpart.
(j) Electric boilers as defined in this subpart.
(k) An electric utility steam generating unit as defined in this subpart.
Section 63.11196 is amended by revising paragraphs (a)(1) and (b) to read as follows:
§63.11196 What are my compliance dates? 
(a) *	*	*
(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 March 21, 2014.
*	*	*	*	*
	(b) If you start up a new affected source on or before May 20, 2011, you must achieve compliance with the provisions of this subpart no later than May 20, 2011.
*	*	*	*	*
Section 63.11201 is amended by revising paragraphs (b) and (d) to read as follows:
§63.11201 What standards must I meet?
*	*	*	*	*
(b) You must comply with each work practice standard, emission reduction measure, and management practice specified in Table 2 to this subpart that applies to your boiler. An energy assessment completed on or after January 1, 2008 that meets or is amended to meet the energy assessment requirements in Table 2 to this subpart satisfies the energy assessment requirement. A facility that operates under an energy management program developed according to the ENERGY STAR guideline for energy management, DOE Save Energy Now, or ISO 50001 compatible energy management systems, that includes the affected units, also satisfies the energy assessment requirement.
*	*	*	*	*
(d) These standards apply at all times the affected boiler is operating, except during periods of startup and shutdown as defined in §63.11237, during which time you must comply only with Table 2 to this subpart.
Section 63.11205 is amended by revising paragraphs (b), (c) introductory text, (c)(1), and (c)(1)(i) to read as follows:
§63.11205 What are my general requirements for complying with this subpart?
*	*	*	*	*
(b) You must demonstrate compliance with all applicable emission limits using performance testing, fuel analysis, or continuous monitoring systems (CMS), including a CEMS, a continuous opacity monitoring system (COMS), or a continuous parameter monitoring system (CPMS), where applicable. You may demonstrate compliance with any applicable mercury emission limit using fuel analysis if the emission rate calculated according to §63.11211(c) is less than the applicable emission limit. Otherwise, you must demonstrate compliance using stack testing.
(c) If you demonstrate compliance with any applicable emission limit through performance stack testing and subsequent compliance with operating limits (including the use of CPMS), with a CEMS, or with a COMS, you must develop a site-specific monitoring plan according to the requirements in paragraphs (c)(1) through (3) of this section for the use of any CEMS, COMS, or CPMS. 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 CPMS), you must develop, and submit to the Administrator for approval upon request, a site-specific monitoring plan that addresses paragraphs (c)(1)(i) through (vi) 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. This requirement to develop and submit a site specific monitoring plan does not apply to affected sources with existing CEMS or COMS operated according to the performance specification under Appendix B to part 60 of this chapter and that meet the requirements of §63.11224.
(i) Installation of the CMS sampling probe or other interface at a measurement location relative to each affected process unit such that the measurement is representative of control of the exhaust emissions (e.g., on or downstream of the last control device);
*	*	*	*	*
Section 63.11210 is amended by revising paragraphs (b) and (d), by redesignating paragraph (e) as paragraph (f) and adding new paragraphs (e) and (g) to read as follows:
§63.11210 What are my initial compliance requirements and by what date must I conduct them?
*	*	*	*	*
(b) For existing affected boilers that have applicable emission limits, you must demonstrate initial compliance with the applicable emission limits 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).
*	*	*	*	*
(d) For new or reconstructed affected boilers that have applicable emission limits, you must demonstrate initial compliance with the applicable emission limits no later than 180 calendar days after March 21, 2011 or within 180 calendar days after startup of the source, whichever is later, according to §63.7(a)(2)(ix).
(e) For new or reconstructed affected boilers that have applicable work practice standards or management practices, you are not required to complete an initial performance tune-up, but you are required to complete the applicable biennial or 5-year tune-up as specified in §63.11223 no later than 25 months or 61 months, respectively, after the initial startup of the new or reconstructed affected source.
(f) For affected boilers that ceased burning solid waste consistent with §63.11196(d) and for which your initial compliance date has passed, you must demonstrate compliance within 60 days of the effective date of the waste-to-fuel switch. If you have not conducted your compliance demonstration for this subpart within the previous 12 months, you must complete all compliance demonstrations for this subpart before you commence or recommence combustion of solid waste.
(g) For affected boilers that switch fuels or make a physical modification to the boiler that result in the applicability of a different subcategory, you must demonstrate compliance within 180 days of the effective date of the fuel switch or physical modification consistent with §63.11225(g).
Section 63.11211 is amended by revising paragraphs (a), (b)(1), and (b)(2) to read as follows:
§63.11211 How do I demonstrate initial compliance with the emission limits?
(a) For affected boilers 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, conducting a fuel analysis for each type of fuel burned in your boiler according to §63.11213 and Table 5 to this subpart, establishing operating limits according to §63.11222 , Table 6 to this subpart and paragraph (b) of this section, as applicable, and conducting CMS performance evaluations according to §63.11224. For affected boilers 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, boilers 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) *	*	*
(1) For a wet scrubber, you must establish the minimum liquid flow rate 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 (PM) and mercury emissions, you must establish one set of minimum scrubber liquid flow rate and pressure drop operating limits. If you conduct multiple performance stack tests, you must set the minimum liquid flow rate and pressure drop operating limits at the highest minimum values established during the performance stack tests.
(2) For an electrostatic precipitator operated with a wet scrubber, you must establish the minimum secondary voltage and secondary amperage (or total secondary electric power), as defined in §63.11237, as your operating limits during the three-run performance stack test. 
*	*	*	*	*
Section 63.11212 is amended by revising paragraphs (b) and (e) to read as follows:
§63.11212 What stack tests and procedures must I use for the performance tests?
*	*	*	*	*
(b) You must conduct each stack test according to the requirements in Table 4 to this subpart. Boilers that use a CEMS for carbon monoxide (CO) are exempt from the initial carbon monoxide performance testing in Table 4 to this subpart and the oxygen concentration operating limit requirement specified in Table 3 to this subpart.
*	*	*	*	*
(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 concentrations and the measured mercury concentrations that result from the performance test to pounds (lb) per million British thermal units (MMBtu) heat input emission rates.
Section 63.11214 is amended by revising paragraph (c) to read as follows:
§63.11214 How do I demonstrate initial compliance with the work practice standard, emission reduction measures, and management practice?
*	*	*	*	*
(c) If you own or operate an existing affected boiler with a heat input capacity of 10 million Btu per hour (MMBtu/hr) or greater, you must submit a signed certification in the Notification of Compliance Status report that an energy assessment of the boiler and its energy use systems was completed according to Table 2 to this subpart and is an accurate depiction of your facility.
*	*	*	*	*
Section 63.11220 is amended by revising the section heading and paragraphs (a), (b), and (c) and removing paragraphs (d), and (e). The revisions read as follows:
§63.11220 When must I conduct subsequent performance tests or fuel analyses?
(a) If your boiler has a heat input capacity of 10 MMBtu/hr or greater, you must conduct all applicable performance (stack) tests according to §63.11212 on a triennial basis, except as specified in paragraphs (b) and (c) of this section. Triennial performance tests must be completed no more than 37 months after the previous performance test.
(b) When demonstrating initial compliance with the PM emission limit, if your oil-fired boiler's performance test results show that your PM emissions are equal to or less than half of the PM emission limit, you do not need to conduct further performance tests for PM but must continue to comply with all applicable operating limits and monitoring requirements. If your initial performance test results show that your PM emissions are greater than half of the PM emission limit, you must conduct subsequent performance tests as specified in paragraph (a) of this section.
(c) 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 as specified in paragraphs (c)(1) and (c)(2) of this section. If you plan to burn a new type of fuel or fuel mixture, you must conduct a fuel analysis before burning the new type of fuel or mixture in your boiler. You must recalculate the mercury emission rate using Equation 1 of §63.11211. The recalculated mercury emission rate must be less than the applicable emission limit.
(1) When demonstrating initial compliance with the mercury emission limit, if the mercury constituents in the fuel or fuel mixture are measured to be equal to or less than half of the mercury emission limit, you do not need to conduct further fuel analysis sampling but must continue to comply with all applicable operating limits and monitoring requirements.
(2) When demonstrating initial compliance with the mercury emission limit, if the mercury constituents in the fuel or fuel mixture are greater than half of the mercury emission limit, you must conduct quarterly sampling.
Section 63.11221 is amended by revising the section heading, and paragraphs (a) through (d) to read as follows:
§63.11221 Is there a minimum amount of monitoring data I must obtain? 
(a) You must monitor and collect data according to this section and the site-specific monitoring plan required by §63.11205(c). 
(b) You must operate the monitoring system and collect data at all required intervals at all times the affected source is operating and compliance is required, except for periods of monitoring system malfunctions or out-of-control periods (see §63.8(c)(7) of this part), 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, required zero and span adjustments, and scheduled CMS maintenance as defined in your site-specific monitoring plan. A monitoring system malfunction is any sudden, infrequent, not reasonably preventable failure of the monitoring system to provide valid data. Monitoring system failures that are caused in part by poor maintenance or careless operation are not malfunctions. You are required to complete 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 practicable.
      (c)  You may not use data collected during monitoring system malfunctions or out-of-control periods as specified in your site-specific monitoring plan, repairs associated with monitoring system malfunctions or out-of-control periods, or required monitoring system quality assurance or quality control activities in calculations used to report emissions or operating levels. Any such periods must be reported according to the requirements in §63.11225. You must use all the data collected during all other periods in assessing the operation of the control device and associated control system.
      (d) Except for periods of monitoring system malfunctions or monitoring system out-of-control periods, repairs associated with monitoring system malfunctions or monitoring system out-of-control periods, and required monitoring system quality assurance or quality control activities (including, as applicable, calibration checks and required zero and span adjustments), failure to collect required data is a deviation of the monitoring requirements.
Section 63.11223 is amended by revising paragraphs (a), (b) introductory text, (b)(3), (b)(5), (b)(6) introductory text, (b)(6)(iii), and (c), and adding paragraphs (d) through (f) to read as follows:
§63.11223 How do I demonstrate continuous compliance with the work practice and management practice standards?
(a) For affected sources subject to the work practice standard or the management practices of a tune-up, you must conduct a performance tune-up according to paragraph (b) of this section and keep records as required in § 63.11225(c) to demonstrate continuous compliance. You must conduct the tune-up while burning the type of fuel (or fuels in the case of boilers that routinely burn two types of fuels at the same time) that provided the majority of the heat input to the boiler over the 12 months prior to the tune-up.
(b) Except as specified in paragraphs (c) through (f) of this section, you must conduct a tune-up of the boiler biennially to demonstrate continuous compliance as specified in paragraphs (b)(1) through (7) of this section. Each biennial tune-up must be conducted no more than 25 months after the previous tune-up. For a new or reconstructed boiler, the first biennial tune-up must be no later than 25 months after the initial startup of the new or reconstructed boiler.
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(3) Inspect the system controlling the air-to-fuel ratio, as applicable, and ensure that it is correctly calibrated and functioning properly (you may delay the inspection until the next scheduled unit shutdown, but you must inspect each system controlling the air-to-fuel ratio at least once every 36 months).
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(5) Measure the concentrations in the effluent stream of 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, as long as it is the same basis before and after the adjustments are made). Measurements may be taken using a portable carbon monoxide analyzer.
(6) Maintain onsite and submit, if requested by the Administrator, a report containing the information in paragraphs (b)(6)(i) through (iii) of this section.
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(iii) The type and amount of fuel used over the 12 months prior to the tune-up of the boiler, but only if the unit was physically and legally capable of using more than one type of fuel during that period. Units sharing a fuel meter may estimate the fuel use by each unit.
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(c) Boilers with an oxygen trim system that maintains an optimum air-to-fuel ratio must conduct a tune-up of the boiler every 5 years as specified in paragraphs (b)(1) through (7) of this section. Each 5-year tune-up must be conducted no more than 61 months after the previous tune-up. For a new or reconstructed boiler with an oxygen trim system, the first 5-year tune-up must be no later than 61 months after the initial startup. You may delay the burner inspection specified in paragraph (b)(1) of this section and inspection of the system controlling the air-to-fuel ratio specified in paragraph (b)(3) of this section until the next scheduled unit shutdown, but you must inspect each burner and system controlling the air-to-fuel ratio at least once every 72 months.
(d) Seasonal boilers must conduct a tune-up every 5 years as specified in paragraphs (b)(1) through (7) of this section. Each 5-year tune-up must be conducted no more than 61 months after the previous tune-up. For a new or reconstructed seasonal boiler, the first 5-year tune-up must be no later than 61 months after the initial startup. You may delay the burner inspection specified in paragraph (b)(1) of this section and inspection of the system controlling the air-to-fuel ratio specified in paragraph (b)(3) of this section until the next scheduled unit shutdown, but you must inspect each burner and system controlling the air-to-fuel ratio at least once every 72 months.
(e) Oil-fired boilers with a heat input capacity of equal to or less than 5 MMBtu/hr must conduct a tune-up every 5 years as specified in paragraphs (b)(1) through (7) of this section. Each 5-year tune-up must be conducted no more than 61 months after the previous tune-up. For a new or reconstructed oil-fired boiler with a heat input capacity of equal to or less than 5 MMBtu/hr, the first 5-year tune-up must be no later than 61 months after the initial startup. You may delay the burner inspection specified in paragraph (b)(1) of this section and inspection of the system controlling the air-to-fuel ratio specified in paragraph (b)(3) of this section until the next scheduled unit shutdown, but you must inspect each burner and system controlling the air-to-fuel ratio at least once every 72 months.
(f) If you own or operate an existing or new coal-fired boiler, a new biomass-fired boiler, or a new oil-fired boiler with a heat input capacity of 10 MMBtu/hr 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.
Section 63.11224 is amended by deleting paragraph (d)(5), revising paragraphs (a) introductory text, (a)(1), (a)(2), (a)(5), (a)(6), (c)(1) introductory text, (c)(2) introductory text, (d) introductory text, (d)(1) - (4), (e) introductory text, (e)(6), and (f)(7), and adding paragraph (a)(7) to read as follows:
§63.11224 What are my monitoring, installation, operation, and maintenance requirements? 
(a) If your boiler is subject to a CO emission limit in Table 1 to this subpart, you must either install, operate, and maintain a CEMS for CO and oxygen according to the procedures in paragraphs (a)(1) through (6) of this section, or install, operate, and maintain an oxygen analyzer system as defined in §63.11237 according to paragraphs (a)(7) and (d) of this section by the compliance date specified in §63.11196. Where a certified CO CEMS is used, the carbon monoxide level shall be monitored at the outlet of the boiler, after any add-on controls or flue gas recirculation system and before release to the atmosphere. Boilers that use a CO CEMS are exempt from the initial CO performance testing and oxygen concentration operating limit requirements specified in §63.11211(a) of this subpart. Oxygen monitors and oxygen trim systems must be installed to monitor oxygen in the boiler flue gas, boiler firebox, or other appropriate intermediate location.
(1) Each CO CEMS must be installed, operated, and maintained according to the applicable procedures under Performance Specification 4, 4A, or 4B at 40 CFR part 60, appendix B, and each oxygen CEMS must be installed, operated, and maintained according to Performance Specification 3 at 40 CFR part 60, appendix B. Both the CO and oxygen CEMS must also be installed, operated, and maintained 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 Performance Specifications 3 and 4, 4A, or 4B at 40 CFR part 60, appendix B.
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(5) You must calculate 1-hour arithmetic averages, corrected to 3 percent oxygen from each hour of CO CEMS data in parts per million CO concentrations. Calculate a 10-day rolling average from all of the 1-hour averages collected for the 10-day operating period. Use Equation 19-19 in section 12.4.1 of Method 19 of 40 CFR part 60, appendix A-7 for calculating the average CO concentration from the hourly values.
(6) For purposes of collecting CO data, you must operate the CO CEMS as specified in §63.11221(b). For purposes of calculating data averages, you must use all the data collected during all periods in assessing compliance, except that you must exclude certain data as specified in §63.11221(c). Periods when CO data are unavailable may constitute monitoring deviations as specified in §63.11221(d). 
(7) You must operate the oxygen analyzer system at or above the minimum percent oxygen by volume that is established as the operating limit for oxygen according to Table 6 to this subpart when firing the fuel or fuel mixture utilized during the most recent CO performance stack test. Operation of oxygen trim systems to meet these requirements shall not be done in a manner which compromises furnace safety.
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(1) For each 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 (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.
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(2) In your site-specific monitoring plan, you must also address paragraphs (c)(2)(i) through (iii) of this section.
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(d) If you have an operating limit that requires the use of a CMS, you must install, operate, and maintain each CPMS according to the procedures in paragraphs (d)(1) through (5) of this section.
(1) The CPMS must complete a minimum of one cycle of operation for each successive 15-minute period. You must have a minimum of four successive cycles of operation to have a valid hour of data.
(2)  You must calculate 1-hour arithmetic averages from each hour of CPMS data in units of the operating limit and determine the 30-day rolling average of all recorded readings, except as provided in §63.11221(c). Calculate a 30-day rolling average from all of the 1-hour averages collected for the 30-day operating period using Equation 2 of this section.
      30-day average	= i=1nHpvin       (Eq.2)
Where:
      Hpvi	=	the hourly parameter value for hour i
      n	=	the number of valid hourly parameter values
            collected over 30 boiler operating days

(3) For purposes of collecting CO data, you must operate the CPMS as specified in §63.11221(b). For purposes of calculating data averages, you must use all the data collected during all periods in assessing compliance, except that you must exclude certain data as specified in §63.11221(c). Periods when CPMS data are unavailable may constitute monitoring deviations as specified in §63.11221(d).
(4) Record the results of each inspection, calibration, and validation check.
(e) If you have an applicable opacity operating limit under this rule, you must install, operate, certify and maintain each COMS according to the procedures in paragraphs (e)(1) through (7) of this section by the compliance date specified in §63.11196.
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(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 quarterly performance audit, or an annual zero alignment audit.
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(7) For positive pressure fabric filter systems that do not duct all compartments or cells to a common stack, a bag leak detection system must be installed in each baghouse compartment or cell.
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Section 63.11225 is amended by revising paragraph (a) introductory text, (a)(4), (a)(5), (b) introductory text, (b)(2), (c) introductory text, (c)(2) introductory text, (c)(2)(ii), (d), (e), and (g); and by adding (a)(6), and (c)(2)(iii) through (v) to read as follows:
§63.11225 What are my notification, reporting, and recordkeeping, requirements?
(a) You must submit the notifications specified in paragraphs (a)(1) through (a)(6) of this section to the administrator.
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      (4) You must submit the Notification of Compliance Status in no later than 120 days after the applicable compliance date specified in §63.11196 unless you must conduct a performance stack test. If you must conduct a performance stack test, you must submit the Notification of Compliance Status within 60 days of completing the performance stack test. You must submit the Notification of Compliance Status in accordance with paragraph (a)(4)(vi) of this section. The Notification of Compliance Status must include the information and certification(s) of compliance in paragraphs (a)(4)(i) through (v) of this section, as applicable, and signed by a responsible official: 
      (i) You must submit the information required in §63.9(h)(2), except the performance tests, opacity or visible emission observations, CMS performance evaluations, and other monitoring procedures or methods that were conducted in §63.9(h)(2)(i)(B). If you conduct any opacity or visible emission observations, or other monitoring procedures or methods, you must submit that data to the Administrator at the appropriate address listed in §63.13.  
      (ii)``This facility complies with the requirements in §63.11214 to conduct an initial tune-up of the boiler.''
      (iii) ``This facility has had an energy assessment performed according to §63.11214(c).'' 
      (iv) 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 §63.11224 and will operate each bag leak detection system according to the plan.''
      (v) For units that do not qualify for a statutory exemption as provided in section 129(g)(1) of the Clean Air Act: ``No secondary materials that are solid waste were combusted in any affected unit.''
      (vi) The notification must be submitted electronically using the Compliance and Emissions Data Reporting Interface (CEDRI) that is accessed through EPA's Central Data Exchange (CDX) (www.epa.gov/cdx). However, if the reporting form specific to this subpart is not available in CEDRI at the time that the report is due, the written Notification of Compliance Status must be submitted to the Administrator at the appropriate address listed in §63.13.
	(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, you must include in the Notification of Compliance Status the date of the test and a summary of the results, not a complete test report, relative to this subpart.
	(6) A dual-fuel fired boiler meeting the definition of a gas-fired boiler can be classified as an existing affected oil-fired boiler and subject to all relevant requirements in the oil subcategory if a notification is submitted as an oil-fired boiler by January 20, 2014.
(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 (4) of this section. You must submit the report by March 15 if you had any instance described by paragraph (b)(3) of this section. For boilers that are subject only to a requirement to conduct a biennial or 5-year tune-up according to § 63.11223(a) and not subject to emission limits or operating limits, you may prepare only a biennial or 5-year compliance report as specified in paragraphs (b)(1) and (2) of this section.
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(2) Statement by a responsible official, with the official's name, title, phone number, email address, and signature, certifying the truth, accuracy and completeness of the notification and a statement of whether the source has complied with all the relevant standards and other requirements of this subpart. 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 §63.11223 to conduct a biennial or 5-year tune-up, as applicable, of each boiler."
(ii) For units that do not qualify for a statutory exemption as provided in section 129(g)(1) of the Clean Air Act: "No secondary materials that are solid waste were combusted in any affected unit."
(iii) "This facility complies with the requirement in §63.11214(d) and §63.11223(f) to minimize the boiler's time spent during startup and shutdown following the manufacturer's recommended procedures."
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(c) You must maintain the records specified in paragraphs (c)(1) through (7) of this section.
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(2) You must keep records to document conformance with the work practices, emission reduction measures, and management practices required by §63.11214 and §63.11223 as specified in paragraphs (c)(2)(i) through (v) of this section.
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      (ii) For operating units that combust non-hazardous secondary materials that have been determined not to be solid waste pursuant to §241.3(b)(1) of this chapter, you must keep a record which documents how the secondary material meets each of the legitimacy criteria under §241.3(d)(1). If you combust a fuel that has been processed from a discarded non-hazardous secondary material pursuant to §241.3(b)(4) of this chapter, you must keep records as to how the operations that produced the fuel satisfies the definition of processing in §241.2 and each of the legitimacy criteria in §241.3(d)(1) of this chapter. If the fuel received a non-waste determination pursuant to the petition process submitted under §241.3(c) of this chapter, you must keep a record that documents how the fuel satisfies the requirements of the petition process. For operating units that combust non-hazardous secondary materials as fuel per §241.4, you must keep records documenting that the material is a listed non-waste under §241.4(a). 
(iii) For each boiler required to conduct an energy assessment, you must keep a copy of the energy assessment report.
(iv) For each boiler subject to an emission limit in Table 1 to this subpart, you must also keep records of monthly fuel use by each boiler, including the type(s) of fuel and amount(s) used.
(v) You must keep records of days of operation by each boiler that meets the definition of seasonal boiler.
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(d) Your records must be in a form suitable and readily available for expeditious review. You must keep each record for 5 years following the date of each recorded action. You must keep each record onsite or be accessible from a central location by computer or other means that instantly provide access at the site for at least 2 years after the date of each recorded action. You may keep the records off site for the remaining 3 years.
      (e)(1) Within 60 days after the date of completing each performance test(defined in §63.2) as required by this subpart you must submit the results of the performance tests, including any associated fuel analyses, required by this subpart to EPA's WebFIRE database by using CEDRI that is accessed through EPA's CDX (www.epa.gov/cdx). Performance test data must be submitted in the file format generated through use of EPA's Electronic Reporting Tool (ERT) (see http://www.epa.gov/ttn/chief/ert/index.html). Only data collected using test methods on the ERT website are subject to this requirement for submitting reports electronically to WebFIRE. Owners or operators who claim that some of the information being submitted for performance tests is confidential business information (CBI) must submit a complete ERT file including information claimed to be CBI on a compact disk or other commonly used electronic storage media (including, but not limited to, flash drives) to EPA. The electronic media must be clearly marked as CBI and mailed to U.S. EPA/OAPQS/CORE CBI Office, Attention: WebFIRE Administrator, MD C404-02, 4930 Old Page Rd., Durham, NC  27703. The same ERT file with the CBI omitted must be submitted to EPA via CDX as described earlier in this paragraph. At the discretion of the delegated authority, you must also submit these reports, including the confidential business information, to the delegated authority in the format specified by the delegated authority. For any performance test conducted using test methods that are not listed on the ERT website, the owner or operator shall submit the results of the performance test in paper submissions to the Administrator.
 (2) Within 60 days after the date of completing each CEMS performance evaluation test as defined in §63.2, you must submit relative accuracy test audit (RATA) data to EPA's CDX by using CEDRI in accordance with paragraph (h)(1) of this section.  Only RATA pollutants that can be documented with the ERT (as listed on the ERT website) are subject to this requirement. For any performance evaluations with no corresponding RATA pollutants listed on the ERT website, the owner or operator shall submit the results of the performance evaluation in paper submissions to the Administrator.
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(g) If you have switched fuels or made a physical change to the boiler, and this fuel switch or change resulted 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 notice of the date upon which you switched fuels within 30 days of the change. 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 have switched fuels or were modified, and the date of the notice.
(2) The date upon which the fuel switch or modification occurred.
Section 63.11226 is amended by revising the section, including the section heading, to read as follows:
§63.11226 Affirmative Defense for Violation of Emission Standards During Malfunction
In response to an action to enforce the standards set forth in §63.11201 you may assert an affirmative defense to a claim for civil penalties for violations of such standards that are caused by malfunction, as defined at §63.2. Appropriate penalties may be assessed; however, if you fail to meet your burden of proving all of the requirements in the affirmative defense, the affirmative defense shall not be available for claims for injunctive relief.
(a) To establish the affirmative defense in any action to enforce such a standard, you must timely meet the reporting requirements in paragraph (b) of this section, and must prove by a preponderance of evidence that:
(1) The violation: 
(i) Was caused by a sudden, infrequent, and unavoidable failure of air pollution control equipment, process equipment, or a process to operate in a normal or usual manner; and
(ii) Could not have been prevented through careful planning, proper design or better operation and maintenance practices; and
(iii) Did not stem from any activity or event that could have been foreseen and avoided, or planned for; and
(iv) Was not part of a recurring pattern indicative of inadequate design, operation, or maintenance; and
(2) Repairs were made as expeditiously as possible when a violation occurred. Off-shift and overtime labor were used, to the extent practicable to make these repairs; and
(3) The frequency, amount, and duration of the violation (including any bypass) were minimized to the maximum extent practicable; and
(4) If the violation resulted from a bypass of control equipment or a process, then the bypass was unavoidable to prevent loss of life, personal injury, or severe property damage; and
(5) All possible steps were taken to minimize the impact of the violation on ambient air quality, the environment, and human health; and
(6) All emissions monitoring and control systems were kept in operation if at all possible, consistent with safety and good air pollution control practices; and
(7) All of the actions in response to the violations were documented by properly signed, contemporaneous operating logs; and
(8) At all times, the affected source was operated in a manner consistent with good practices for minimizing emissions; and
(9) A written root cause analysis has been prepared, the purpose of which is to determine, correct, and eliminate the primary causes of the malfunction and the violation resulting from the malfunction event at issue. The analysis shall also specify, using best monitoring methods and engineering judgment, the amount of excess emissions that were the result of the malfunction. 
(b) Report. The owner or operator seeking to assert an affirmative defense shall submit a written report to the Administrator with all necessary supporting documentation, that it has met the requirements set forth in §63.11201 of this subpart. This affirmative defense report shall be included in the first periodic compliance, deviation report or excess emission report otherwise required after the initial occurrence of the violation of the relevant standard (which may be the end of any applicable averaging period). If such compliance, deviation report or excess emission report is due less than 45 days after the initial occurrence of the violation, the affirmative defense report may be included in the second compliance, deviation report or excess emission report due after the initial occurrence of the violation of the relevant standard.
Section 63.11236 is amended by revising paragraph (a) to read as follows:
§63.11236 Who implements and enforces this subpart? 
(a) This subpart can be implemented and enforced by EPA or an administrator such as your state, local, or tribal agency. If the EPA Administrator has delegated authority to your state, local, or tribal agency, then that agency has the authority to implement and enforce this subpart. You should contact your EPA Regional Office to find out if implementation and enforcement of this subpart is delegated to your state, local, or tribal agency.
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Section 63.11237 is amended as follows:
a. By adding new definitions in alphabetical order for "10-day rolling average," "30-day rolling average," "Biodiesel," "Calendar year," "Daily block average," "Distillate oil," "Electric boiler," "Electric utility steam generating unit (EGU)," "Energy management program," "Load fraction," "Minimum scrubber pressure drop," "Minimum sorbent injection rate," "Minimum total secondary electric power," "Operating day," "Oxygen analyzer system," "Oxygen trim system," "Process heater," "Residential boiler," "Residual oil," "Seasonal boiler," "Shutdown," "Startup," "Solid fuel," "Temporary boiler," "Tune-up," "Vegetable oil," and "Wet scrubber."
b. By revising the definitions for "Annual heat input basis," "Bag leak detection system," "Biomass subcategory," "Boiler," "Boiler system," "Deviation," "Dry scrubber," "Energy assessment," "Energy use system," "Federally enforceable," "Gas-fired boiler," "Heat input," "Hot water heater," "Institutional boiler," "Minimum activated carbon injection rate," "Minimum scrubber liquid flow rate," "Natural gas," "Oil subcategory," "Period of natural gas curtailment or supply interruption," "Qualified Energy Assessor," and "Waste heat boiler."
c. By deleting the definitions for "Minimum PM scrubber pressure drop," "Minimum sorbent flow rate," "Minimum voltage or amperage."
§63.11237 What definitions apply to this subpart? 
	10-day rolling average means the arithmetic mean of all valid hours of data from 10 successive operating days, except for periods of startup and shutdown and periods when the unit is not operating.
30-day rolling average means the arithmetic mean of all valid hours of data from 30 successive operating days, except for periods of startup and shutdown and periods when the unit is not operating.
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Annual heat input basis means the heat input for the 12 months preceding the compliance demonstration.
Bag leak detection system means a group of instruments that are capable of monitoring particulate matter loadings in the exhaust of a fabric filter (i.e., baghouse) in order to detect bag failures. A bag leak detection system includes, but is not limited to, an instrument that operates on electrodynamic, triboelectric, light scattering, light transmittance, or other principle to monitor relative particulate matter loadings.
Biodiesel means a mono-akyl ester derived from biomass and conforming to ASTM D6751 - 11b, Standard Specification for Biodiesel Fuel Blend Stock (B100) for Middle Distillate Fuels (incorporated by reference, see §63.14).
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Biomass subcategory includes any boiler that burns any biomass and is not in the coal subcategory.
Boiler means an enclosed device using controlled flame combustion in which water is heated to recover thermal energy in the form of steam and/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. A device combusting solid waste, as defined in §241.3, is not a boiler unless the device is exempt from the definition of a solid waste incineration unit as provided in section 129(g)(1) of the Clean Air Act. Waste heat boilers, process heaters, and autoclaves are excluded from this definition.
Boiler system means the boiler and associated components, such as, feedwater systems, combustion air systems, fuel systems (including burners), blowdown systems, combustion control systems, steam systems, and condensate return systems, directly connected to and serving the energy use systems.
Calendar year means the period between January 1 and December 31, inclusive, for a given year.
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Daily block average means the arithmetic mean of all valid emission concentrations or parameter levels recorded when a unit is operating measured over the 24-hour period from 12 am (midnight) to 12 am (midnight), except for periods of startup and shutdown or downtime.
Deviation (1) 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 applicable requirement or obligation established by this subpart including, but not limited to, any emission limit, operating limit, or work practice standard; or
(ii) Fails to meet any term or condition that is adopted to implement an applicable requirement in this subpart and that is included in the operating permit for any affected source required to obtain such a permit.
(2) A deviation is not always a violation. 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.
Distillate oil means fuel oils that contain 0.05 weight percent nitrogen or less and comply with the specifications for fuel oil numbers 1 and 2, as defined by the American Society of Testing and Materials in ASTM D396 (incorporated by reference, see § 63.14) or diesel fuel oil numbers 1 and 2, as defined by the American Society for Testing and Materials in ASTM D975 (incorporated by reference, see §63.14).
Dry scrubber means an add-on air pollution control system that injects dry alkaline sorbent (dry injection) or sprays an alkaline sorbent (spray dryer) to react with and neutralize acid gas in the exhaust stream forming a dry powder material. Sorbent injection systems used as control devices in fluidized bed boilers and process heaters are included in this definition. A dry scrubber is a dry control system.
Electric boiler means a boiler in which electric heating serves as the source of heat. Electric boilers that burn gaseous or liquid fuel during periods of electrical power curtailment or failure are included in this definition.
Electric utility steam generating unit (EGU) means a fossil fuel-fired combustion unit of more than 25 megawatts that serves a generator that produces electricity for sale. A fossil fuel-fired unit that cogenerates steam and electricity and supplies more than one-third of its potential electric output capacity and more than 25 megawatts electrical output to any utility power distribution system for sale is considered an electric utility steam generating unit. To be "capable of combusting" fossil fuels, an EGU would need to have these fuels allowed in their operating permits and have the appropriate fuel handling facilities on-site or otherwise available (e.g., coal handling equipment, including coal storage area, belts and conveyers, pulverizers, etc.; oil storage facilities). In addition, fossil fuel-fired EGU means any EGU that fired fossil fuel for more than 10.0 percent of the average annual heat input in any 3 consecutive calendar years or for more than 15.0 percent of the annual heat input during any one calendar year after April 16, 2015.
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 electrostatic precipitator is usually a dry control system.
Energy assessment means the following for the emission units covered by this subpart:
(1) The energy assessment for facilities with affected boilers using less than 0.3 trillion Btu per year (TBtu/year) heat input will be 8 on-site technical labor hours in length maximum, but may be longer at the discretion of the owner or operator of the affected source. The boiler system(s) and any on-site energy use system(s) 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 an 8-hour energy assessment.
(2) The energy assessment for facilities with affected boilers using 0.3 to 1.0 TBtu/year will be 24 on-site technical labor hours in length maximum, but may be longer at the discretion of the owner or operator of the affected source. The boiler system(s) and any on-site 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 24-hour energy assessment.
(3) The energy assessment for facilities with affected boilers using greater than 1.0 TBtu/year will be up to 24 on-site technical labor hours in length for the first TBtu/year plus 8 on-site technical labor hours for every additional 1.0 TBtu/year not to exceed 160 on-site technical hours, but may be longer at the discretion of the owner or operator of the affected source. The boiler system(s) and any on-site 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.
(4) The on-site energy use system(s) serving as the basis for the percent of affected boiler(s) energy output in (1), (2), and (3) above may be segmented by production area or energy use area as most logical and applicable to the specific facility being assessed (e.g., product X manufacturing area; product Y drying area; Building Z).
Energy management program means a program according to the ENERGY STAR guideline for energy management, DOE Save Energy Now, or ISO 50001 compatible energy management systems (e.g., includes a set of practices and procedures designed to manage energy use that are demonstrated by the facility's energy policies, a facility energy manager and other staffing responsibilities, energy performance measurement and tracking methods, an energy saving goal, action plans, operating procedures, internal reporting requirements, and periodic review intervals used at the facility).
Energy use system includes the following systems located on the site of the affected boiler that use energy provided by the boiler: (i) process heating; compressed air systems; machine drive (motors, pumps, fans); process cooling; facility heating, ventilation, and air conditioning systems; hot water systems; building envelop; and lighting; or (ii) other systems that use steam or hot water provided by the boiler.
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Federally enforceable means all limitations and conditions that are enforceable by the EPA Administrator, including, but not limited to, the requirements of 40 CFR parts 60, 61, 63, and 65, requirements within any applicable state implementation plan, and any permit requirements established under 40 CFR 52.21 or under 40 CFR 51.18 and 40 CFR 51.24.
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Gas-fired boiler includes any boiler that burns gaseous fuels not combined with any solid fuels, burns liquid fuel only during periods of gas curtailment, gas supply interruption, startups, or periodic testing on liquid fuel. Periodic testing of liquid fuel shall not exceed a combined total of 48 hours during any calendar year.
Heat input means heat derived from combustion of fuel in a boiler and does not include the heat input from preheated combustion air, recirculated flue gases, returned condensate, or exhaust gases from other sources such as gas turbines, internal combustion engines, kilns, etc.
Hot water heater means a closed vessel with a capacity of no more than 120 U.S. gallons in which water is heated by combustion of gaseous, liquid, or biomass fuel and hot water is withdrawn for use external to the vessel. Hot water boilers (i.e., not generating steam) combusting gaseous, liquid, or biomass fuel with a heat input capacity of less than 1.6 million Btu per hour are included in this definition. The 120 U.S. gallon capacity threshold to be considered a hot water heater is independent of the 1.6 MMBtu/hr heat input capacity threshold for hot water boilers. Hot water heater also means a tankless unit that provides on demand hot water.
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Institutional boiler means a boiler used in institutional establishments such as, but not limited to, medical centers, nursing homes, research centers, institutions of higher education, elementary and secondary schools, libraries, religious establishments, and governmental buildings to provide electricity, steam, and/or hot water.
Liquid fuel includes, but is not limited to, distillate oil, residual oil, any form of liquid fuel derived from petroleum, used oil, liquid biofuels, biodiesel, and vegetable oil.
Load fraction means the actual heat input of a boiler divided by heat input during the performance test that established the minimum sorbent injection rate or minimum activated carbon injection rate, expressed as a fraction (e.g., for 50 percent load the load fraction is 0.5).
Minimum activated carbon injection rate means load fraction multiplied by the lowest 2-hour average 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.
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Minimum scrubber liquid flow rate means the lowest 1-hour average scrubber liquid flow rate (e.g., to the PM scrubber) measured according to Table 6 to this subpart during the most recent performance stack test demonstrating compliance with the applicable emission limit.
Minimum scrubber pressure drop means the lowest 1-hour average scrubber pressure drop measured according to Table 6 to this subpart during the most recent performance stack test demonstrating compliance with the applicable emission limit.	
Minimum sorbent injection rate means load fraction multiplied by the lowest 2-hour average sorbent 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 total secondary electric power means the lowest hourly average total secondary electric power determined from the values of secondary voltage and secondary current 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; or 
(2) Liquefied petroleum gas, as defined by the American Society for Testing and Materials in ASTM D1835 (incorporated by reference, see §63.14).
(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).
(4) Propane or propane-derived synthetic natural gas. Propane means a colorless gas derived from petroleum and natural gas, with the molecular structure C3H8.
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 only during periods of gas curtailment, gas supply interruptions, startups, or for periodic testing are not included in this definition. Periodic testing on liquid fuel shall not exceed a combined total of 48 hours during any calendar year..
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Operating day means a 24-hour period between 12 midnight and the following midnight during which any fuel is combusted at any time in the boiler unit. It is not necessary for fuel to be combusted for the entire 24-hour period.
Oxygen analyzer system means all equipment required to determine the oxygen content of a gas stream and used to monitor oxygen in the boiler flue gas, boiler firebox, or other appropriate intermediate location. This definition includes oxygen trim systems. The source owner or operator must install, calibrate, maintain, and operate the oxygen analyzer system in accordance with the manufacturer's recommendations. 
Oxygen trim system means a system of monitors that is used to maintain excess air at the desired level in a combustion device. A typical system consists of a flue gas oxygen and/or carbon monoxide monitor that automatically provides a feedback signal to the combustion air controller.
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Period of gas curtailment or supply interruption means a period of time during which the supply of gaseous fuel to an affected boiler is restricted for reasons beyond the control of the facility. The act of entering into a contractual agreement with a supplier of natural gas established for curtailment purposes does not constitute a reason that is under the control of a facility for the purposes of this definition. An increase in the cost or unit price of natural gas due to normal market fluctuations not during periods of supplier delivery restriction does not constitute a period of natural gas curtailment or supply interruption. On-site gaseous fuel system emergencies or equipment failures may qualify as periods of supply interruption when the emergency or failure is beyond the control of the facility.
Process heater means an enclosed device using controlled flame, and the unit's primary purpose is to transfer heat indirectly to a process material (liquid, gas, or solid) or to a heat transfer material (e.g., glycol or a mixture of glycol and water) for use in a process unit, instead of generating steam. Process heaters are devices in which the combustion gases do not come into direct contact with process materials. Process heaters include units that heat water/water mixtures for pool heating, sidewalk heating, cooling tower water heating, power washing, or oil heating.
Qualified energy assessor means a person or persons who have demonstrated capabilities to evaluate energy savings opportunities for steam generation, process heat, and major steam and process heat using systems, as applicable to the facility. Qualified energy assessors may be company employees or outside specialists.
Residential boiler means a boiler used in a dwelling containing four or fewer family units to provide heat and/or hot water and/or as part of a residential combined heat and power system. This definition includes boilers used primarily to provide heat and/or hot water for a dwelling containing four or fewer families located at an institutional facility (e.g., university campus, military base, church grounds) or commercial/industrial facility (e.g., farm).
Residual oil means crude oil, fuel oil numbers 1 and 2 that have a nitrogen content greater than 0.05 weight percent, and all fuel oil numbers 4, 5, and 6, as defined by the American Society of Testing and Materials in ASTM D396 - 10 (incorporated by reference, see §63.14(b)).
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Seasonal boiler means a boiler that undergoes a shutdown for a period of at least 7 consecutive months (or 210 consecutive days) each 12-month period due to seasonal market conditions, except for periodic testing. Periodic testing shall not exceed a combined total of 15 days during the 7-month shutdown. This definition only applies to boilers that would otherwise be included in the biomass subcategory or the oil subcategory. 
Shutdown means the cessation of operation of a boiler for any purpose. Shutdown begins either when none of the steam or heat from the boiler is supplied for heating and/or producing electricity, or for any other purpose, or at the point of no fuel being fired in the boiler, whichever is earlier. Shutdown ends when there is both no steam or heat being supplied and no fuel being fired in the boiler.
Solid fossil fuel includes, but is not limited to, coal, coke, petroleum coke, and tire derived fuel.
Solid fuel means any solid fossil fuel or biomass or bio-based solid fuel.
Startup means either the first-ever firing of fuel in a boiler for the purpose of supplying steam or heat for heating and/or producing electricity, or for any other purpose, or the firing of fuel in a boiler after a shutdown event for any purpose. Startup ends when any of the steam or heat from the boiler is supplied for heating and/or producing electricity, or for any other purpose.
Temporary boiler means any gaseous or liquid fuel boiler that is designed to, and is capable of, being carried or moved from one location to another by means of, for example, wheels, skids, carrying handles, dollies, trailers, or platforms. A boiler is not a temporary boiler if any one of the following conditions exists:
(1) The equipment is attached to a foundation.
(2) The boiler or a replacement remains at a location within the facility and performs the same or similar function for more than 12 consecutive months, unless the regulatory agency approves an extension. An extension may be granted by the regulating agency upon petition by the owner or operator of a unit specifying the basis for such a request. Any temporary boiler that replaces a temporary boiler at a location within the facility and performs the same or similar function will be included in calculating the consecutive time period.
(3) The equipment is located at a seasonal facility and operates during the full annual operating period of the seasonal facility, remains at the facility for at least 2 years, and operates at that facility for at least 3 months each year.
(4) The equipment is moved from one location to another within the facility in an attempt to circumvent the residence time requirements of this definition.
Tune-up means adjustments made to a boiler in accordance with the procedures outlined in §63.11223(b).
Vegetable oil means oils extracted from vegetation.
Waste heat boiler means a device that recovers normally unused energy and converts it to usable heat. Waste heat boilers are also referred to as heat recovery steam generators. This definition includes both fired and unfired waste heat boilers.
Wet scrubber means any add-on air pollution control device that mixes an aqueous stream or slurry with the exhaust gases from a boiler to control emissions of particulate matter or to absorb and neutralize acid gases, such as hydrogen chloride. A wet scrubber creates an aqueous stream or slurry as a byproduct of the emissions control process.
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Tables 1, 2, 6 and 7 to subpart JJJJJJ are revised to read as follows:
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 MMBtu/hr or greater
a.	PM (Filterable)
3.0E-02 lb per MMBtu of heat input.

b.	Mercury
2.2E-05 lb per MMBtu of heat input.

c.	CO
420 ppm by volume on a dry basis corrected to 3 percent oxygen (3-run average or 10-day rolling average).
2.	New coal-fired boiler with heat input capacity of between 10 and 30 MMBtu/hr
a.	PM (Filterable)
4.2E-01 lb per MMBtu of heat input.

b.	Mercury

2.2E-05 lb per MMBtu of heat input.

c.	CO
420 ppm by volume on a dry basis corrected to 3 percent oxygen (3-run average or 10-day rolling average).
3.	New biomass-fired boiler with heat input capacity of 30 MMBtu/hr or greater
a.	PM (Filterable)
3.0E-02 lb per MMBtu of heat input.
4.	New biomass fired boiler with heat input capacity of between 10 and 30 MMBtu/hr
a.	PM (Filterable)
7.0E-02 lb per MMBtu of heat input.
5.	New oil-fired boiler with heat input capacity of 10 MMBtu/hr or greater
a.	PM (Filterable)
3.0E-02 lb per MMBtu of heat input.
6.	Existing coal 
(units with heat input capacity of 10 MMBtu/hr or greater) 
a.		Mercury
2.2E-05 lb per MMBtu of heat input.

b.	CO
420 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 § 63.11201, you must comply with the following applicable work practice standards, emission reduction measures, and management practices:
                   If your boiler is in this subcategory...
                        You must meet the following...
1. Existing or new coal, new biomass, and new oil (units with heat input capacity of 10 MMBtu/hr or greater) 
Minimize the boiler's 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 coal (units with heat input capacity of less than 10 MMBtu/hr)
Conduct an initial tune-up as specified in §63.11214, and conduct a tune-up of the boiler biennially as specified in §63.11223.
3. New coal (units with heat input capacity of less than 10 MMBtu/hr) 
Conduct a tune-up of the boiler biennially as specified in §63.11223.

4. Existing oil-fired boilers with heat input capacity greater than 5 MMBtu/hr, and all existing biomass-fired boilers 
Conduct an initial tune-up as specified in §63.11214, and conduct a tune-up of the boiler biennially as specified in §63.11223.

5. New oil-fired boilers with heat input capacity greater than 5 MMBtu/hr, and all new biomass-fired boilers 
Conduct a tune-up of the boiler biennially as specified in §63.11223.

6. Existing seasonal boilers 
Conduct an initial tune-up as specified in §63.11214, and conduct a tune-up of the boiler every 5 years as specified in §63.11223.

7. New seasonal boilers 
Conduct a tune-up of the boiler every 5 years as specified in §63.11223.

8. Existing oil-fired boiler with heat input capacity of equal to or less than 5 MMBtu/hr
Conduct an initial tune-up as specified in §63.11214, and conduct a tune-up of the boiler every 5 years as specified in §63.11223.
9. New oil-fired boiler with heat input capacity of equal to or less than 5 MMBtu/hr
Conduct a tune-up of the boiler every 5 years as specified in §63.11223.
10. Existing or new boilers with an oxygen trim system that maintains an optimum air-to-fuel ratio
Conduct a tune-up of the boiler every 5 years as specified in §63.11223.
11. Existing coal, biomass, or oil (units with heat input capacity of 10 MMBtu/hr and greater) 
Must have a one-time energy assessment performed by a qualified energy assessor or must operate under an energy management program developed according to the ENERGY STAR guideline for energy management, DOE Save Energy Now, or ISO 50001 compatible energy management systems, that includes the affected units. An energy assessment completed on or after January 1, 2008, that meets or is amended to meet the energy assessment requirements in this table satisfies the energy assessment requirement. Energy assessor approval and qualification requirements are waived in instances where past or amended energy assessments are used to meet the energy assessment requirements. The energy assessment must include: 

(1) A visual inspection of the boiler system.
(2) An evaluation of operating characteristics of the affected boiler systems, specifications of energy use systems, operating and maintenance procedures, and unusual operating constraints,
(3) An inventory of major energy use systems consuming energy from affected boiler(s) and which are under control of the boiler owner or operator,
(4) A review of available architectural and engineering plans, facility operation and maintenance procedures and logs, and fuel usage,
(5) A list of major energy conservation measures that are within the facility's control,
(6) A list of the energy savings potential of the energy conservation measures identified, and
(7) 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 except during periods of startup and shutdown...
1.	Fabric filter control
a.	Maintain opacity to less than or equal to 10 percent opacity (daily block average); OR

b.	Install and operate a bag leak detection system according to §63.11224 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 30-day rolling average secondary electric power input of the electrostatic precipitator at or above the minimum secondary electric power measured during the most recent performance test demonstrating compliance with the particulate matter emission limitations. 
3. Wet PM scrubber control
Maintain the 30-day rolling average pressure drop at or above the minimum scrubber pressure drop across the wet scrubber and the 30-day rolling average liquid flow-rate at or above the minimum scrubber liquid flow rate measured during the most recent performance test demonstrating compliance with the PM emission limitation. 
4.	Dry sorbent or activated carbon injection control
Maintain the 30-day rolling average sorbent or activated carbon injection rate at or above the minimum sorbent injection rate or minimum activated carbon injection rate measured during the most recent performance test demonstrating compliance with the mercury emissions limitation. When your boiler operates at lower loads, multiply your sorbent or activated 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, multiply 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. Boilers must maintain opacity to less than or equal to 10 percent opacity (daily block average).
6. Fuel analysis
Maintain the fuel type or fuel mixture (annual average) such that the mercury emission rates calculated according to §63.11211(c) are 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. Oxygen analyzer system 
For boilers subject to a CO emission limit that demonstrate compliance with an oxygen analyzer system as specified in §63.11224(a), maintain the 30-day rolling average oxygen level at or above the minimum oxygen level measured during the most recent CO performance stack test.

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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
1. PM or mercury
a. Wet scrubber operating parameters
i. Establish a site-specific minimum scrubber pressure drop and minimum scrubber liquid flow rate operating limits according to §63.11211(b)
(1) Data from the pressure drop and liquid flow rate monitors and the PM or mercury performance stack tests
(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.
 
b. Electrostatic precipitator operating parameters 
i. Establish a site-specific minimum secondary electric power operating limit according to §63.11211(b)
(1) Data from the secondary electric power monitors and the PM or mercury performance stack tests
(a) You must collect secondary electric power input data every 15 minutes during the entire period of the performance stack tests;
 



(b) Determine the average secondary electric 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.
2. Mercury 
a. Dry sorbent or activated carbon injection rate operating parameters
i. Establish a site-specific minimum sorbent or activated carbon injection rate operating limit according to §63.11211(b)
(1) Data from the sorbent or activated carbon injection rate monitors and the mercury performance stack tests
(a) You must collect sorbent or activated carbon injection rate data every 15 minutes during the entire period of the performance stack tests;




(b) Determine the average sorbent or 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.




(c) When your unit operates at lower loads, multiply your sorbent or 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 rate.
3. CO
a. Oxygen
i. Establish a unit-specific limit for minimum oxygen level.
(1) Data from the oxygen analyzer system specified in §63.11224(a).
(a) You must collect oxygen data every 15 minutes during the entire period of the performance stack tests;




(b) Determine the average hourly oxygen concentration
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.
4. Any pollutant for which
compliance is demonstrated
by a performance
stack test.
a. Boiler operating load.
i. Establish a unit-specific
limit for maximum operating
load according to
§63.11212(c).
(1) Data from the operating
load monitors (fuel feed monitors or
steam generation monitors).
(a) You must collect operating
load data (fuel feed rate or steam generation
data) every 15
minutes during the entire
period of the performance test.
(b) Determine the average
operating load by computing
the hourly averages using all of the 15-minute readings taken during each performance test.
(c) Determine the average
of the three test run
averages during the performance
test, and multiply
this by 1.1 (110
percent) as your operating limit.
                                       
Table 7 to Subpart JJJJJJ of Part 63  --  Demonstrating Continuous Compliance
As stated in §63.11222, you must show continuous compliance with the emission limitations for each boiler according to the following:
             If you must meet the following operating limits . . .
              You must demonstrate continuous compliance by . . .
1. Opacity
a. Collecting the opacity monitoring system data according to §63.11224(e) and §63.11221; and
 
b. Reducing the opacity monitoring data to 6-minute averages; and
 
c. Maintaining opacity to less than or equal to 10 percent (daily block average).
2. Fabric Filter Bag Leak Detection Operation
Installing and operating a bag leak detection system according to §63.11224(f) and operating the fabric filter such that the requirements in §63.11222(a)(4) are met.
3. Wet Scrubber Pressure Drop and Liquid Flow Rate
a. Collecting the pressure drop and liquid flow rate monitoring system data according to §§63.11224 and 63.11221; and
 
b. Reducing the data to 30-day rolling averages; and
 
c. Maintaining the 30-day rolling average pressure drop and liquid flow rate at or above the operating limits established during the performance test according to §63.11211.
4. Dry Scrubber Sorbent or Activated Carbon Injection Rate
a. Collecting the sorbent or activated carbon injection rate monitoring system data for the dry scrubber according to §§63.11224 and 63.11221; and
 
b. Reducing the data to 30-day rolling averages; and
 
c. Maintaining the 30-day rolling average sorbent or activated carbon injection rate at or above the minimum sorbent or activated carbon injection rate as defined in §63.11237.
5. Electrostatic Precipitator Total Secondary Electric Power Input
a. Collecting the total secondary electric power input monitoring system data for the electrostatic precipitator according to §§63.11224 and 63.11221; and
 
b. Reducing the data to 30-day rolling averages; and
 
c. Maintaining the 30-day rolling average total secondary electric power input at or above the operating limits established during the performance test according to §63.11211.
6. Fuel Pollutant Content
a. Only burning the fuel types and fuel mixtures used to demonstrate compliance with the applicable emission limit according to §63.11213 as applicable; and
 
b. Keeping monthly records of fuel use according to §63.11222.
7. Oxygen content
a. Continuously monitor the oxygen content of flue gas according to §63.11224.

b. Reducing the data to 30-day rolling averages; and

c. Maintain the 30-day rolling average oxygen content at or above the operating limit established during the most recent CO performance test.
8. CO emissions
a. Continuously monitor the CO concentration in the combustion exhaust according to §63.11224(a).

b. Correcting the data to 3 percent oxygen, and reducing the data to one-hour and daily block averages;

c. Reducing the data from the daily averages to 10-day rolling averages;

d. Maintaining the 10-day rolling average CO concentration at or below the applicable emission limit in Tables 1 of this subpart. 
9. Boiler operating load 
a. Collecting operating load data (fuel feed rate or steam generation data) every 15 minutes.
b. Reducing the data to 30-day rolling averages; and
c. Maintaining the 30-day rolling average at or below the operating limit established during the performance test according to §63.11212(c).
 

 
