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**ENVIRONMENTAL PROTECTION AGENCY 40 CFR Part 63**  **[ EPA**  **- HQ**  **- OAR**  **- 2002**  **- 0058; FRL**  **- ]**  **RIN 2060 -**  **AG69 National Emission Standards for Hazardous Air Pollutants for** 

**Major Sources: Industrial**  **/ ,**  **Commercial /**  **, and Institutional**  **Boilers and Process Heaters**

**AGENCY** : Environmental Protection Agency (EPA).
**ACTION** : Proposed rule.
**SUMMARY** : On September 13, 2004, under authority of section 112 of the Clean Air Act, EPA promulgated national emission standards for hazardous air pol lutants for new and existing industrial/commercial/institutional boilers and process heaters. On June 19, 2007 , the United States Court of Appeals for the District of Columbia Circuit vacated and remanded the national emission standards for hazardous air pollutants for industrial/commercial/institutional boilers and process heaters.

I n response to the court’s vacatur and remand , this action would requir e all major sources to meet hazardous air pollutants emissions standards reflecting the application of th e maximum achievable control technology. The proposed rule would protect2 air quality and promote public health by reducing emissions of

t he HAP listed in section 112(b)(1) of the C lean A ir A ct
. **DATES:** Comments must be received on or before [ INSERT DATE 4 5
DAYS AFTER PUBLICATION IN THE FEDERAL REGISTER ]. Under the Paperwork Reduction Act, comments on the information collection provisions are best assured of having full effect if t he Office of Management and Budget (OMB) receives a copy of your comments

on or before [ INSERT DATE 30 DAYS AFTER PUBLICATION IN THE
FEDERAL REGISTER ].
**ADDRESSES:** Submit your comments, identified by Docket ID No.

EPA

- HQ

- OAR

- 200 2

- 0058 , by one of the following methods:

• http://www.regulati ons.gov . Follow the instructions for submitting comments.

• http://www.epa.gov/oar/docket.html . Follow the instructions for submitting comments on the EPA Air and Radiation Docket Web Site.

• E

- mail : Comm ents may be sent by electronic mail (e

mail) to a - and

- r - docket@epa.gov , Attention Docket ID

No. EPA

- HQ

- OAR

- 200 2

- 0058.

• Fax

• : Fax your comments to: (202) 566

- 9744, Docket ID
No. EPA

- HQ

- OAR

- 200 2

- 0058. Mail : Send your comments to: EPA Docket Center (EPA/DC) , Environmental Protection Agency, Mailcode:3 2822T, 1200 Pennsylvania Ave., NW, Washington, DC 20460, Docket ID No. EPA

- HQ

- OAR

- 200 2

- 0058. Please include a total of two copies. In addition, please mail a copy of your comments on the information collection provisions to the Office of Information and Regulatory Affairs, O MB, Attn: Desk Officer for EPA, 725 17th St., NW, Washington, DC 20503.

• Hand Delivery or Courier : Deliver your comments to: EPA Docket Cent er, EPA West, Room 3334, 1301 Constitution Ave., NW, Washington, DC 20460. Such deliveries are only accepted during the Docket’s normal hours of operation (8:30 a.m. to 4:30 p.m., Monday through Friday, excluding legal holiday) , and special arrangements s hould be made for deliveries of boxed information. Instructions : All submission s must include agency name and docket number or Regulatory Information Number (RIN) for this rulemaking. All comments will be posted without change and may be made available o nline at http://www.regulations.gov , including any personal information provided, unless the comment includes information claimed to be confidential business information (CBI) or other information whose disclosur e is restricted by statute. Do not submit information that you4 consider to be CBI or otherwise protected through http://www.regulations.gov or e - mail. The http://www.r egulations.gov w eb site is an “anonymous access” system, which means EPA will not know your identity or contact information unless you provide it in the body of your comment. If you send an e

- mail comment directly to EPA without going through http://www.regulations.gov , your e - mail address will be automatically captured and included as part of the comment that is placed in the public docket and made available on the Internet. If you submit an electronic comment , EPA recommends that you include your name and other contact information in the body of your comment and with any disk or CD

- ROM you submit. If EPA cannot read your comment due to technical difficulties and cannot contact you for clarification, EPA may n ot be able to consider your comment. Electronic files should avoid the use of special characters, any form of encryption, and be free of any defects or viruses. Docket : All documents in the docket are listed in the http://www.regulations.gov index. Although listed in the index, some information is not publicly available, e.g., CBI or other information whose disclosure is restricted by statute. Certain other material, such as copyrighted material, will be publi cly available only in hard copy form. Publicly available docket5 materials are available either electronically in http://www.regulations.gov or in hard copy at the EPA Docket Center, Room 3334, 1301 Constitution Ave., NW, Washington, DC. The Public Reading Room is open from 8:30 a.m. to 4:30 p.m., Monday through Friday, excluding legal holidays. The telephone number for the Public Reading Room is (202) 566

- 1744, and the telephone number for the Air Docket is (20 2) 566

- 1742.
**FOR FURTHER INFORMATION CONTACT:** Mr. Brian Shrager, Energy Strategies Group, Sector Policies and Programs Division, (D243

- 01), Office of Air Quality Planning and Standards, U.S. Environmental Protection Agency, Research Triangle Park, North
C arolina 27711; Telephone number: (919) 541

- 7689; Fax number (919) 541

- 5450; E

- mail address: shrager.brian@epa.gov

. **SUPPLEMENTARY INFORMATION** : The information presented in this preamble is organized as follows:

I. General Information A. Does this action apply to me? B. What should I consider as I prepare my comments to EPA? C. Where can I get a copy of this document? D. W hen would a public hearing occur? I I. Background Information A. What is the statutory authority for the proposed rule ? B. Summary o f the N atural R esources D efense C ouncil v. EPA Decision C. Summary of Other Related Court Decisions D. EPA’s Response to the Vacatur E
. What is the relationship betw een the proposed rule and other combustion rules?6

F
. What are the health effects of po llutants emitted from industrial/commercial/institutional boilers and process heaters? II I
. Summary of the Proposed Rule A. What source categories are affected by the proposed rule? B. What is the affected source? C
. Does the proposed rule apply to me? D
. What emission limitations and work practice standards must I meet? E
. What are the s tartup, s hutdown, and m alfunction (SSM) requirements? F. What are the testing and initial compliance requirements? G. What are the continuous compliance requirement s? H. What are the notification, recordkeeping and reporting requirements? I. Submission of Emissions Test Results to EPA I V
. Rationale for the Proposed Rule A. How did EPA determine which sources would be regulated under the proposed rule? B. How did EPA select the format for the proposed rule? C. How did EPA determine the proposed emission limitations for existing units? D. How did EPA determine the MACT floor for existing units? E. How did EPA consider beyond

- the

- floor for existing units? F. Shou ld EPA consider different subcategories for solid fuel boilers and process heaters? G. How did EPA determine the proposed emission limitations for new units? H. How did EPA determine the MACT floor for new units? I. How did EPA consider beyond

- the

- floor for new units? J
. What other compliance alternatives were considered? K
. How did we select the compliance requirements? L
. What alternative compliance provisions are being proposed ? M
. How did EPA determine compliance times for the proposed rule? N. How did EPA determine the required records and reports for th is proposed rule? O
. How does the proposed rule affect permits? P. Alternative Standard for Consideration V. Impacts of the Proposed Rule A. What are the air impacts? B. What are the water a nd solid waste impacts? C. What are the energy impacts? D. What are the control costs? E. What are the economic impacts? F
. What are the social costs and benefits of the proposed rule?7 VI. Public Participation and Request for Comment VI I
. Relationsh ip of the Proposed Action to Section 112(c)(6) of the CAA VII I
. Statutory and Executive Order Reviews A. Executive Order 12866, Regulatory Planning and Review B. Executive Order 13132, Federalism C. Executive Order 13175, Consultation and Coordination with Indian Tribal Governments D. Executive Order 13045, Protection of Children from Environmental Health Risks and Safety Risks E. Unfunded Mandates Reform Act of 1995 F. Regulatory Flexibility Act as Amended by the Small Business Regulatory Enforc ement Fairness Act (RFA) of 1996 SBREFA), 5 U.S.C. 601 et Seq
. G. Paperwork Reduction Act H. National Technology Transfer and Advancement Act I. Executive Order 13211, Actions Concerning Regulations That Significantly Affect Energy Supply, Distribut ion, or Use J. Executive Order 12898: Federal Actions to Address Environmental Justice in Minority Populations and Low

- Income Populations **I. General Information**

A. Does this action apply to me? The regulated categories and entities potentially affe cted by the proposed standards include:

Category NAICS code 1 Examples of potentially regulated entities Any industry using a boiler or process heater as defined in the proposed rule 211 Extractors of crude petroleum and natural gas

321 Manufacturers of lumber and wood products 322 Pulp and paper mills 325 Chemical manufacturers8

324 Petroleum refineries, and manufacturers of coal products 316, 326, 339 Manufacturers of rubber and miscellaneous plastic products 331 Steel works, blast furnac es 332 Electroplating, plating, polishing, anodizing, and coloring 336 Manufacturers of motor vehicle parts and accessories 221 Electric, gas, and sanitary services 622 Health services 611 Educational services 1 North American Industry Classific ation System. This table is not intended to be exhaustive, but rather provides a guide for readers regarding entities likely to be affected by this action. To determine whether your facility, company, business, organization, etc., would be regulated by this action, you should examine the applicability criteria in 40 CFR 63. 7485 of subpart DDDDD ( National Emission Standards for Hazardous Air Pollutants ( NESHAP ) for Industrial, C ommercial, and Institution Boilers and Process Heaters). If you have any questions regarding the applicability of this action to a particular entity, consult either the air permitting authority for the entity or your EPA regional representative as listed in 40 CFR 63.13 of subpart A (General Provisions).9

B
. W hat should I consider as I prepare my comments to EPA? Do not submit information containing CBI to EPA through http://www.regulations.gov or e - mail. Send or deliver information identified as CBI only to the fol lowing address: Roberto Morales, OAQPS Document Control Officer ( C404

- 02) , Office of Air Quality Planning and Standards, U.S. Environmental Protection Agency, Research Triangle Park, North Carolina 27711, Attention: Docket ID EPA

- HQ

- OAR

- 2002

- 0058. Clearl y mark the part or all of the information that you claim to be CBI. For CBI information in a disk or CD

- ROM that you mail to EPA, mark the outside of the disk or CD

- ROM as CBI and then identify electronically within the disk or CD

- ROM the specific informa tion that is claimed as CBI. In addition to one complete version of the comment that includes information claimed as CBI, a copy of the comment that does not contain the information claimed as CBI must be submitted for inclusion in the public docket. Inf ormation so marked will not be disclosed except in accordance with procedures set forth in 40 CFR part 2.
C
. Where can I get a copy of this document? In addition to being available in the docket, an electronic copy of this proposed action will also be a vailable on the Worldwide Web (WWW) through the Technology Transfer Network (TTN). Following signature, a copy of the proposed action will10 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.

D. When would a public hearing occur? If anyone contacts EPA requesting to speak at a public hearing concerning the proposed rule by [ INSERT DATE 10 DAYS
AFTER PUBLICATION IN THE FEDERAL REGISTER ] , we will hold a public hearing on [ INSERT DATE 15 DAYS AFTER PUBLICATION IN THE
FEDERAL REGISTER ] . Persons interested in presenting oral

te stimony at the hearing, or inquiring as to whether a hearing will be held, should contact Ms. Pamela Garrett, Energy Strategies Group, at ( 919) 541

- 7966 at least 2 days in advance of the hearing. If a public hearing is held, it will be held at 10 a.m. at the EPA’s Campus located at 109 T.W. Alexander Drive in Research Triangle Park, NC, or at an alternate site nearby.

**I I**  **. Background Information** 

A. What is the statutory authority for th is proposed rule ? Section 112 (d) of the Clean Air Act ( CAA ) requires EPA to set emissions standards for hazardous air pollutants ( HAP ) emitted by major stationary source s based on the performance of the maximum achievable control technology (MACT). The MACT standards for existing sources must be at least as stringent as11

t he average emissions limitation achieved by the best performing 12 percent of existing sources (for which the A dministrator has emissions information) or the best performing 5 sources for

source categories with less than 30 sources (CAA section 112(d)(3)(A ) and (B)). This level of minimum stringency is called the MACT floor. For new sources, MACT standards must be at least as stringent as the control level achieved in practice by the best controlled similar source (CAA section 112(d)(3)).

EPA also must c onsider more stringent “ beyond

- the

- floor ” control options. When considering beyond

- the

- floor options, EPA must consider not only the maximum degree of reduction in emissions of HAP, but must take into account costs, energy, and nonair environmental impact s when doing so.
CAA s ection 112(c)(6) requires EPA to list categories and subcategories of sources a ssuri ng that sources accounting for not less than 90 percent of the aggregate emissions of each such pollutant ( alkylated lead compounds; polycyclic organ ic matter; hexachlorobenzene; mercury; polychlorinated byphenyls; 2,3,7,8

- tetrachlorodibenzofurans; and 2,3,7,8

- tetrachloroidibenzo

- p - dioxin ) are subject to standards under sub section 112(d)(2) or (d)(4)

. Standards established under CAA section 112(d)(2) must reflect the performance of MACT. “Industrial Coal Combustion ,” “Industrial Oil Combustion,”12

“ Industrial Wood/Wood Residue Combustion,” “Commercial Coal Combustion,” “Commercial Oil Combustion,” and “Commercial Wood/Wood Residue Combustion” are liste d as source categor ies for regulation pursuant to CAA section 112(c)(6) due to emissions of polycyclic organic matter (POM) and mercury (63 FR 17838, 17848, April 10, 1998)

. In the documentation for the 112(c)(6) listing, the commercial fuel combustion ca tegories included institutional fuel combustion (“1990 Emissions Inventory of Section 112(c)(6) Pollutants, Final Report,” April 1998).
CAA s ection 129(a)(1)(A) requires EPA to establish specific performance standards, including emission limitations, for

“ solid waste incineration units ” generally, and, in particular, for “ solid waste incineration units combusting commercial or industrial waste ” (section 129(a)(1)(D)). Section 129 defines

“ solid waste incineration unit ” as “ a distinct operating unit of

any facility which combusts any solid waste material from commercial or industrial establishments or the general public. ” Section 129(g)(1). Section 129 also provides that “ solid waste ” shall have the meaning established by EPA pursuant to its authority und er the Resource Conservation and Recovery Act

. Section 129(g)(6).13

In Natural Resources Defense Council v. EPA, 489 F. 3d 1250, 1257

– 61 (D.C. Cir. 2007), the court vacated the Commercial and Industrial Solid Waste Incineration ( CISWI) Definitions Rule, 70 FR 55568 (Sept ember 22, 2005), which EPA issued pursuant to CAA section 129(a)(1)(D). In that rule, EPA defined the term “ commercial or industrial solid waste incineration unit ” to mean a combustion unit that combusts

“ commercial or industrial waste. ” T he rule defined “ commercial or industrial waste ” to mean waste combusted at a unit that does

not recover thermal energy from the combustion for a useful

purpose. Under these definitions, only those units that combusted commercial or industrial waste and w ere not designed to, or did not operate to, recover thermal energy from the combustion would be subject to section 129 standards. The District of Columbia Circuit ( DC Circuit ) rejected the definitions contained in the CISWI Definitions Rule and interprete d the term “ solid waste incineration unit ” in CAA section 129(g)(1) “ to unambiguously include among the incineration units subject to its standards any facility that combusts any commercial or industrial solid waste material at all

— subject to the four st atutory exceptions identified in [CAA section 129(g)(1).] ” NRDC v. EPA, 489 F.3d 1250, 1257

– 58.14
CAA section 129 covers any facility that combusts any solid

waste; CAA section 112(g)(6) directs the Agency to the Resource Conservation and Recovery Act ( RCR A ) in terms of the definition of solid waste . The Agency is in the process of defining solid

waste for purposes of Subtitle D of RCRA. EPA initiated a rulemaking to define which secondary materials are “ solid waste ” for purposes of subtitle D (nonhazardo us waste) of RCRA when burned in a combustion unit. ( See Advance Notice of Proposed Rulemaking ( 74 FR 41 , January 2, 2009) soliciting comment on whether certain secondary materials used as alternative fuels or ingredients are solid wastes within the meani ng of Subtitle D of
RCRA
. ) If a unit combusts solid waste, it is subject to CAA section 129 of the Act, unless it falls within one of the four specified exceptions in CAA section 129(g). Th e solid waste definitional rulemaking under RCRA is being

propose d in a parallel action and is relevant to this proceeding because some industrial, commercial, or institutional boilers and process heaters combust secondary materials as alternative fuels. If an industrial, commercial, or institutional boilers and proces s heaters combust s secondary materials that are solid waste under the proposed definitional rule, those units would be subject to section 129. The units subject to this rule include those15 industrial, commercial, or institutional boilers and process heate rs that do not combust solid waste. EPA recognizes that it has imperfect information on the exact nature of the secondary materials which boilers and process heater s combust, including, for example, how much processing of such materials occurs, if any. W e nevertheless used the information currently available to the Agency to determine which materials are solid waste and therefore subject to CAA section 129, which are not solid waste and therefore subject to CAA section 112.

B. Summary of the N atural R eso urces D efense C ouncil v. EPA Decision
On September 13, 2004 , EPA issued the NESHAP for Industrial, Commercial, and Institutional Boilers and Process Heaters (40 CFR 55218) (the Boiler MACT). We identified 18 subcategories of boilers and process heaters e mitting four different types of HAPs. See 69 FR 55,223

- 24. EPA set out to establish the MACT floor for each subcategory emitting each HAP according to the effectiveness of various add

- on technologies. ( See 68 FR 1660, 1674 , Jan. 13, 2003 (proposed rule). ) Applying this methodology, EPA set 25 numerical emission standards. The 2004 final rule established emission limitations for particulate matter ( PM ), as a surrogate for non

- mercury HAP metals, mercury , and hydrogen chloride (HCl), as a surrogate for ac id gas HAP ,16 for existing large solid fuel

- fired sources only. For the remaining 47 boiler subcategory/HAP emissions, EPA determined that the appropriate MACT floor was “no emissions reduction” because “the best

- performing sources were not achieving emissi ons reductions through the use of an emission control system and there were no other appropriate methods by which boilers and process heaters could reduce HAP emissions.” ( 69 FR 55,233. ) Accordingly, we established no standard s. I n addition, we set risk

- based standards, also known as health

based compliance alternative s, as alternatives to the MACT

- based standards for hydrogen chloride and manganese. EPA issued emissions standards for CISWI units on December 1, 2000, and as part of that rulemaking, defi ned the term

“ c ommercial and industrial waste” to mean solid waste combusted in an enclosed device using controlled flame combustion without energy recovery that is a distinct operating unit of any commercial or industrial facility. In response to a petit ion for reconsideration, EPA filed a motion for voluntary remand, which the court granted on September 6, 2001. On remand, EPA solicited comments on the CISWI Rule’s definitions of “solid waste,” “commercial and industrial waste” and “CISWI unit.” On Sep tember 22, 2005, EPA issued the CISWI Definitions Rule, which contained definitions that were substantively the same as those17 issued before reconsideration. In particular, the 2005 CISWI Definitions Rule defined “commercial or industrial waste” to include only waste that is combusted at a facility that cannot or does not use a process that recovers thermal energy from the combustion for a useful purpose. EPA received separate petitions from environmental groups , industry, and municipalities seeking judic ial review of the NESHAP for Industrial, Commercial, and Institutional Boilers and

Process Heaters (Boiler MACT ) as well as amendments to definitional terms in the Standards of Performance for New Stationary Sources and Emission Guidelines for Existing Sou rces: Commercial and Industrial Solid Waste Incineration Units (CISWI Definitions Rule), promulga ted pursuant to CAA section 129

. The environmental organizations c hallenge d the CISWI Definitions Rule on the ground that its definition of “commercial or in dustrial waste” was inconsistent with the plain language of CAA section 129 and therefore impermissibly constrict ed the class of “solid waste incineration unit[s]” that we re subject to the emission standards of the CISWI Rule. The e nvironmental

groups als o challenge d specific emission standards that EPA promulgated in the Boiler MACT and EPA’s methodology for setting them. The municipalities

— the American Municipal Power

- Ohio, Inc. and six of its members, the cities of Dover, Hamilton,18 Orrville, Painesvi lle, Shelby and St. Mary’s,

— challenge d the Boiler MACT on the grounds that EPA failed to comply with the requirements of the Regulatory Flexibility Act (RFA) and that the standards as applied to small municipal utilities are unlawful. As explained furthe r below, the Court conclude d that EPA’s definition of “commercial or industrial waste,” as incorporated in the definition of “commercial and industrial solid waste incineration unit” (CISWI unit), was inconsistent with the plain language of CAA section 129 and that the CISWI Definitions Rule

must , therefore , be vacated. The Court also vacated the Boiler MACT, finding that the Boiler MACT must be substantially revised as a consequence of the vacatur and remand of the CISWI Definitions Rule. In its decision, t he Court agree d with the environmental petitioners that EPA’s definition of “commercial or industrial waste,” as incorporated in the definition of CISWI units, conflict ed with the plain language of CAA section 129 (g)(1). That provision defines “solid wa ste incineration unit” to mean “any facility which combusts any solid waste material” from certain types of establishments, with four specific exclusions. The Court stated that, based on the use of the term “any” and the specific exclusions for only certa in types of facilities19 from the definition of “solid waste incineration unit,” CAA section 129 unambiguously include s among the incineration units subject to its standards any facility that combusts any commercial or industrial solid waste material at all

— subject only to the four statutory exc lusions

. The Court held that t he definition s EPA promulgated in the CISWI Definitions Rule constrict ed the plain language of CAA section 129(g)(1), because the CISWI Definitions Rule excluded from its universe opera ting units that combusted solid waste and were designed for or operating with energy recovery. Having determined that EPA’s definition of “ commercial and industrial solid waste incineration unit” conflicts with the plain meaning of CAA section 129 and m ust , therefore , be vacated, the Court also vacated the Boiler MACT because it concluded that the Boiler MACT w ould need to be revised because the universe of boilers subject to its standards will be different once EPA revises the CISWI definition s rule con sistent with the Court’s opinion. T he Court did not address petitioners’ specific challenges to the Boiler MACT
. C. Summary of Other Related Court Decisions In March 2007 , the D

. C
. Circuit C ourt issued an opinion ( Sierra Club v. EPA, 479 F. 3d 875 (DC C ir. 2007) ( Brick20

MACT )) vacating and remanding CAA section 112(d) MACT standards for the Brick and Structural Clay Ceramics source categories. Some key holdings in that case were:

**•** Floors for existing sources must reflect the average emission limitation ac hieved by the best

- performing 12 percent of existing sources, not levels EPA considers to be achievable by all sources (479 F. 3d at 880

– 81);

**•** EPA cannot set floors of “ no control. ” The Court reiterated its prior holdings, including National Lime

Ass ociati o n, confirming that EPA must set floor standards for all HAP emitted by the major source, including those

HAP that are not controlled by at

- the

- stack control devices (479 F. 3d at 883);

**•** EPA cannot ignore non

- technology factors that reduce HAP emissions. S pecifically, the Court held that “ EPA’s decision to base floors exclusively on technology even though non

- technology factors affect emissions violates the

Act. ” (479 F. 3d at 883) Based on the Brick MACT decision, we believe a source’s performance resulti ng from the presence or absence of HAP in fuel m aterials must be accounted for in establishing floors; i.e., a low emitter due to low HAP fuel materials can still be a best performer. In addition, the fact that a specific level of21 performance is unintende d is not a legal basis for excluding the source’s performance from consideration. ( National Lime Ass’n, 233 F. 3d at 640. ) The Brick MACT decision also stated that EPA may account for variability in setting floors. However, the court found that EPA erre d in assessing variability because it relied on data from the worst performers to estimate best performers’ variability, and held that “ EPA may not use emission levels of the worst performers to estimate variability of the best performers without a demonst rated relationship between the two. ” ( 479 F. 3d at 882. ) The majority opinion in the Brick MACT case does not address the possibility of subcategorization to address differences in the HAP content of raw materials. However, in his concurring opinion Jud ge Williams stated that EPA’s ability

to create subcategories for sources of different classes, size, or type ( CAA section 112 (d)(1)) may provide a means out of the situation where the floor standards are achieved for some sources, but the same floors can not be achieved for other sources due to differences in local raw materials whose use is essential. ( Id. A t 884

– 85.9 ) A second court opinion is also relevant to this proposal.

In Sierra Club v. EPA , 551 F. 3d 1019 (D

. C
. Cir. 2008) , the22
court vacated the portion of the regulations contained in the General Provisions which exempt major sources from MACT standards during periods of startup, shutdown and malfunction (SSM). The regulations (in 40 CFR 63.6(f)(1) and 63.6(h)(1)) provided that sources need not comply with the relevant CAA section 112(d) standard during SSM events and instead must

“ minimize emissions

. . . to the greatest extent which is consistent with safety and good air pollution control practices. ” The vacated Boiler MACT d id not contain spe cific provisions covering operation during SSM operating modes; rather it reference d the now

- vacated exemption in the General Provisions. As a result of the court decision, we are addressing SSM in this proposed rulemaking. Discussion of this issue may b e found later in this preamble

. D
. EPA’s Response to the Vacatur In response to the NRDC v. EPA mandate, we initiated an information collection effort entitled “Information Collection Effort for Facilities with Combustion Units .” This information collec tion wa s conducted by EPA’s Office of Air and Radiation pursuant to CAA section 114 to assist the Administrator in developing emissions standards for boilers/process heaters and
CISWI units (collectively, “combustion units”) pursuant to CAA23 sections 112(d) and 129. CAA s ection 114(a) states, in pertinent part: For the purpose of ...(iii) carrying out any provision of this Chapter...(1) the Administrator may require any person who owns or operates any emission source...to

- . . .(D) sample such emissions (in accordance with such procedures or methods, at such locations, at such intervals, during such periods and in such manner as the Administrator shall prescribe); (E) keep records on control equipment parameters, production variables or other indirect data wh en direct monitoring of emissions is impractical.. .(G) provide such other information as the Administrator may reasonably require... There w ere two components to the information collection. To obtain the information necessary to identify and categorize all combustion units potentially affected by the revised standards for boilers/process heaters and for CISWI units, the first component of th e information collection effort solicit ed information from all potentially affected combustion units in the format of an electronic survey. The survey w as submitted to the following facilities: (1) all facilities that submitted an initial notification for the 2004 boiler MACT standard, (2) all facilities identified by S tates as being subject to the 200424
boiler MACT standard, and (3) facilities that are classified as a major source in their Title V permit that have a boiler or process heater listed in their permit. The survey was also sent to units covered by the 2000 CISWI emissions standards (40 CFR

p art 60 s ubpart CCCC) and to facilities that have incineration units that were listed as exempt under the 2000 CISWI standard. Each facility w as required to complete the survey for all combustion units located at the facility. The information requested for each combust ion unit included the u nit d esign,

o peration, a ir p ollution co ntrol d ata , the f uels/ m aterials burned , and available emissions test data, continuous emission monitoring ( CEM ) data, fuel/material analysis data, and

p ermitted and r egulatory emission limits

. T he second component of the information collection request effort consist ed of requiring the owners/operators of 16 9 boilers/process heaters to conduct emission testing for HAP and HAP surrogates. We first analyze d the results of the survey to determine if sufficient emission s data exist ed to develop emission standards under CAA sections 112(d) for all types of boilers/process heater s , all types of materials combusted , and all HAP to be regulated . If data we re not sufficient, then we select ed pools of cand idates to conduct emission testing. We submit ted a list of candidates to stakeholders, including state,25 industry, and environmental stakeholders, who ha d an opportunity to comment on the technical feasibility , the least

- cost impact of the testing program , and the appropriateness of the testing being requested

. We then ma d e a selection of test sites after taking into account stakeholder comments. The sites selected were required to conduct an outlet stack test , consisting of three runs, in accordance with EPA

- approved protocol s , for all of the following pollutants: PM (filterable, condensable, and

PM 2.5 ), dioxins/furans (D/F) , hydrogen chloride/hydrogen fluoride, mercury, metals (including antimony, arsenic, beryllium, cadmium, chromium, cobalt, lead, man ganese, nickel, phosphorus, and selenium), carbon monoxide (CO), total hydrocarbons (THC), formaldehyde, oxides of nitrogen (NOx), and sulfur dioxide (SO2). Six facilities (two coal

- fired, two biomass

- fired, and two gas

- fired boilers) were required to col lect CEM data over 30 operating days using mobile CEM device s for CO, THC , and NOx. The owner/operator of each selected combustion unit was also required to collect and analyze, in accordance with acceptable procedure s , the material(s) fed to the combusti on unit during each stack test. The results of the stack tests and the analyses of materials combusted were required to be submitted to the Agency.26

W hen we compared information on boilers and process heaters from facilities submitting initial notification s to comply with the vacated 2004 Boiler MACT to the information gathering effort conducted for the 2004 Boiler MACT , a large disparity was identified in the number of potentially affected units at major sources of HAP. Since the last combustion unit data gathering effort in 1996 , many sources have shut down, others have selected to operate with a permit limit on their HAP emissions in order to avoid being subject to the B oil er MACT (i.e., synthetic area source) , and some units have switched out older soli d fuel units for newer equipment due to increased insurance and maintenance

costs. Based on the definition of solid waste as set forth in a parallel proposed action, we revise d the population of combustion units subject to CAA section 129 (because they c ombust solid waste) and the population of boilers and process heate rs subject to CAA section 112 (because they do not combust solid waste)

. We then used the new data to develop a revised NESHAP for boilers and process heaters under CAA section 112 and rev ised standards for incineration units covered by CAA section 129. Specifically, the data provid e the Agency with updated information on the number of potentially affected units, available emission test data , and fuel/material analysis data to address vari ability. We are using27
all of the information before the Administrator to calculat e the MACT floors, set emission limits, and evaluat e the emission impacts of various regulatory options for th ese revised rulemaking s . E
. What is the relationship between th is proposed rule and other combustion rules ? The proposed rule regulates source categories covering industrial boilers, institutional boilers, commercial boilers, and process heaters. These source categories potentially include combustion units that ar e already regulated by other MACT standards. Therefore, we are excluding from this proposed rule any boiler or process heater that is subject to regulation under other MACT standard s . In 1986, EPA had codified new source performance standards (NSPS) for industrial boilers (40 CFR part 60, subparts Db and Dc) and revised portions of th ose standards in 1999 and 2006

. The NSPS regulates emissions of PM, SO 2 , and NOx from boilers constructed after June 19, 1984. Sources subject to the NSPS will be subject t o the final CAA section 112(d) standards for boilers and process heaters because it regulates sources of HAP while the NSPS do not. However, in developing the proposed rule, we consider ed the monitoring requirements, testing28 requirements, and recordkeepin g requirements of the NSPS to avoid duplicating requirements.

T his proposed rule addresses the combustion of non

- solid waste materials in boilers and process heaters. If an owner or operator of an affected source subject to t h ese proposed standard s were to start combusting a solid waste (as defined by the Administrator under RCRA) , the affected source would cease to be subject to this action and would instead be subject to regulation under CAA s ection 129. A rulemaking under CAA section 129 is being prop osed in a parallel action and is relevant to this action because it would apply to boilers and process heaters located at a major source that combust any solid

waste. EPA is taking comment on whether a boiler or process heater could then opt back into reg ulation under t hi s proposed rule by taking a federally enforceable restriction precluding the future combustion of any solid waste material.

F
. What are the health effects of pollutants emitted from industrial/commercial/institutional boilers and process heaters ?

T hi s proposed rule protects air quality and promotes the public health by reducing emissions of some of the HAP listed in
CAA section 112(b)(1). As noted above, emissions data collected during development of the proposed rule show that hydrogen chloride emissions represent the predominant HAP emitted by29
industrial , commercial, and industrial (ICI) boilers, accounting for 84 percent of the total HAP emissions. I CI boilers and process heaters also emit lesser amounts of hydrogen fluoride, accounti ng for about 5 percent of total HAP emissions, and metals (arsenic, cadmium, chromium, mercury, manganese, nickel, and lead) accounting for about 0.3 percent of total HAP emissions. Organic HAP (formaldehyde, POM, acetaldehyde, benzene) account for about 11 percent of total HAP emissions. Exposure to these HAP is associated with a variety of adverse health effects. These adverse health effects include chronic health disorders (e.g., irritation of the lung, skin, and mucus membranes, effects on the centra l nervous system, and damage to the kidneys), and acute health disorders (e.g., lung irritation and congestion, alimentary effects such as nausea and vomiting, and effects on the kidney and central nervous system). We have classified two of the HAP as hum an carcinogens (arsenic and chromium VI ) and four as probable human carcinogens (cadmium, lead, dioxins/furans, and nickel) . We do not know the extent to which the adverse health effects described above occur in the populations surrounding these facilitie s. However, to the extent the adverse effects do occur, t hi s proposed rule would reduce emissions and subsequent exposures.

**I II. Summary of th**  **is Proposed Rule** 30 This section summarizes the requirements proposed in today’s action. Section IV below provides our rationale for the proposed requirements.

A. What source categories are affected by th is proposed rule ? Th is proposed rule affects industrial boilers, institutional boilers, commercial boilers, and process heaters. In th is proposed rule , process hea ters are defined as units in which the combustion gases do not directly come into contact with process material or gases in the combustion chamber (e.g., indirect fired). Boiler means an enclosed device using controlled flame combustion and having the pri mary purpose of recovering thermal energy in the form of steam or hot water.

B
. What is the affected source ? The affected source is : (1) the collection of all existing industrial, commercial, or institutional boiler s or process heater s within a subc ategory located at a major facility or (2) each new or reconstructed industrial, commercial, or institutional boiler or process heater located at a major facility that do not combust solid waste, as that term is defined by the Administrator under RCRA

. Th e affected source does not include boilers and process heaters that are subject to another standard under 40 CFR part 63 or a standard established under CAA section 129.31

C
. Does th is proposed rule apply to me ? Th is proposed rule applies to you if you ow n or operate a boiler or process heater at a major source meeting the requirements discussed previously in this preamble. A major source of HAP emissions is any stationary source or group of stationary sources located within a contiguous area and under

co mmon control that emits or has the potential to emit considering controls 10 tons per year or more of any HAP or 25 tons per year or more of any combination of HAP.

D
. What emission limitations and work practice standards must I

meet ? We are proposing th e emission limits presented in Table 1 of this preamble. Emission limits were developed for new and existing sources for eleven subcategories , which we developed based on unit design

. We are proposing that i f your new or existing boiler or process heat er burns more than 10 percent coal on a heat input 1

1 Heat input means heat derived from combustion of fuel in a boiler or process heater and does not include the heat derived from preheated combustion air, recirculated flue gases or exhaust gases from other sources (such as stationary gas turbines, internal combustion engines, and kilns. basis on an annual average , the unit is in one of the coal subcategories. If your new or existing boiler or process heater burns more than 10 percent biomass , on a heat input basis on an annual average, and less than 10 percent coal , on a heat input basis on an annual average , we are proposing that the unit is in32 one of the biomass subcategories. If your new or existing boiler or process heater burns a liquid fuel (such as distillate oil, residual oil) , or a liquid fuel in combination with a gaseous fuel, we are proposing that the unit is in one of the liquid subcategories. If your new or existing boiler or process heater burns gaseous fuel and less than 10 percent, on a heat input basis on an annual ave rage, of liquid or solid fuel , we are proposing that the unit is in one of the gas subcategories

. Table 1. EMISSION LIMITS FOR BOILERS AND PROCESS HEATERS (pounds per million British thermal units)

Subcategor y Particula te Matter (PM) Hydrogen Chloride

(HCl) Mercury (Hg) Carbon Monoxide(CO) (ppm @3%oxygen) Dioxins/ Furans (Total TEQ) (ng/dscm) Existing

– Coal Stoker 0.0 2 0. 0 06 0 0 8 0.0000 03 40 5 0 0.003

Existing

- Coal Fluidized Bed 0.0 2 0. 0 06 0 0 8 0.0000 03 40 3 0 0.002

Existing

– Pulverized Coal 0.0 2 0. 0 06 0 0 8 0.000003 70 9 0 0. 003 00 4

Existing

– Biomass Stoker 0. 07 0 2 0. 0006 006 0. 0000007 000000 9 780 56 0 0. 003 00 4

Existing

- Biomass Fluidized Bed 0. 07 0 2 0. 0006 006 0. 0000007 000000 9 230 2 5 0 0.02

Existing

– Biomass Suspension Burner/Dut 0. 07 0 2 0. 0006 006 0. 000 0007 000000 9 460 1010 0.0333

ch Oven Existing

– Biomass Fuel Cells 0. 07 0 2 0. 0006 006 0. 0000007 000000 9 270 0.02

Existing

- Liquid 0. 004 0. 0 003 0 00 4 0. 0000 08 0 000 0 4 1 0.002

Exis ting

– Gas (NG/RFG) -- -- -- -- --

Existing

– Gas (Other Process Gases) 0. 05 0.000003 0.0000 002 1 0. 008 00 9

Exis ting

– Metal Processing Furnaces -- -- -- -- --

New

– Coal Stoker 0. 0009 00 1 0. 00005 00 00 6 0. 00000 07 00000 2 7 0.003

New

- Coal Fluidized Bed 0. 0009 00 1 0. 00005 00 00 6 0. 0000007 00000 2 40 3 0 0.00003

New

– Pulverized Coal 0. 0009 00 1 0. 00005 00 0 0 6 0. 00000 07 00000 2 1 90 0.002

New

– Biomass Stoker 0. 007 00 8 0. 0006 00 4 0. 000000 0 7 000000 2 780 56 0 0.00005

New

- Biomass Fluidized Bed 0. 007 00 8 0. 0006 00 4 0. 0000000 7 000000 2 40 0.007

New

– Biomass Suspension Burner/Dut ch Oven 0. 007 00 8 0. 0006 00 4 0. 0000000 7 000 000 2 460 1010 0. 0004 0 3

New

– Biomass Fuel Cells 0. 007 00 8 0. 0006 00 4 0. 0000000 7 000000 2 270 0. 03 0 005

New

– Liquid 0.002 0. 0001 000 4 0.0000003 1 0. 000005 00 2 New

– Gas 0.0 005 0.0 002 0.0 00000002 20 0.013 4
(NG/RFG) New

– Gas (Other Process Gases) 0. 002 00 3 0.00000 3 0.0000002 1 0. 008 00 9

New

– Metal P rocess ing Furnaces 0.0 3 0.0 002 0.0 000002 2 0.00 4

The proposed emission limits in the above table apply only

to existing boilers and process heaters that have a designed heat input capacity of 10 million British therma l units (Btu) per hour or greater. Pursuant to CAA section 112(h), we are proposing a work practice standard for two particular class es of existing boilers and process heaters : existing units that have a designed heat input capacity of less than 10 millio n Btu per hour and new and existing units in the Gas 1 ( natural

gas / refinery gas ) subcate gory and in the metal processing process furnaces subcategory . The work practice standard being proposed for these existing boilers and process heaters would require t he implementation of a tune

- up program as described in section III.F of this preamble

. We are also proposing a b eyond

- the

- floor standard for all existing major source facilities having affected boilers or process heaters that would require the performance of an one time energy a ssessment , as described in section III. F of this preamble , by qualified personnel, on the affected units boiler s35 and facility and to implement i dentify any cost

- effective energy conservation measures identified

. W e are also proposing a beyond

- the

- floor standard that would require facilities with boilers or process heaters combusting refinery gas to install and maintain a carbon adsorber bed system to remove mercury from the refinery gas before combustion in a boiler or process heater.

E
. What are the s tartup, s hutdown, and m alfunction (SSM) requirements? The United States Court of Appeals for the District of Columbia Circuit vacated two provisions in EPA’s CAA Section 112 regulations governing the emissions of HAP during periods of
SSM. S ierra Club v. EPA, 551 F.3d 1019 (D.C. Cir. 2008). Specifically, the Court vacated the SSM exemption contained in 40 CFR 63.6(f)(1) and 40 CFR 63.6(h)(1), that are part of a regulation, commonly referred to as the “General Provisions Rule,” that EPA pr omulgated under section 112 of the CAA. When incorporated into CAA Section 112(d) regulations for specific source categories, these two provisions exempt sources from the requirement to comply with the otherwise applicable CAA section 112(d) emission stan dard during periods of SSM. In light of Sierra Club v. EPA, the proposed emission standards summarized in section IV.D of this preamble apply at36 all times. We are not proposing a separate emission standard for the source categories at issue here that app lies during periods of startup and shutdown. We have evaluated whether it is appropriate to have the same standards apply during startup and shutdown as applied to normal operations. The standards that we are proposing are daily or monthly averages based upon emission data which include periods of startup and shutdown. Boilers do not normally startup and shutdown more th an once per day. Thus, w e are not establishing a separate emission standard for these periods because startup and shutdown are part of their normal operations and, therefore, are already addressed by the standards. Periods of startup, normal operations, and shutdown are all predictable and routine aspects of a source’s operations. However, by contrast, malfunction is defined as a “sudde n, infrequent, and not reasonably preventable failure of air pollution control and monitoring equipment, process equipment or a process to operate in a normal or usual manner * * * ’’(40 CFR 63.2). EPA has determined that malfunctions should not be viewed as a distinct operating mode and, therefore, any emissions that occur at such times do not need to be factored into development of CAA section 112(d) standards, which, once promulgated, apply at all times. For example, we note that37
Section 112 uses the c oncept of “best performing” sources in defining MACT, the level of stringency that major source standards must meet . It is reasonable to interpret section 112(d) as not requiring EPA to account for malfunctions in setting emissions standards. Applying th e concept of “best performing” to a source that is malfunctioning presents difficulties. The goal of best performing sources is to operate in such a way as to avoid malfunctions of their units. Moreover, even if malfunctions were considered a distinct

op erating mode, we believe it would be impracticable to take malfunctions into account in setting CAA section 112(d) standards for boilers and process heaters. As noted above, by definition, malfunctions are sudden and unexpected events and it would be diff icult to set a standard that takes into account the myriad different types of malfunctions that can occur across all sources. Moreover, malfunctions can vary in frequency, degree, and duration, further complicating standard setting. For a source that fail s to comply with the applicable Section 112(d) standards during malfunction events, EPA will determine an appropriate response based on, among other things, the good faith efforts of the source to minimize emissions during malfunction periods, including pr eventative and corrective actions, as well as root cause analyses to ascertain38 and rectify excess emissions. EPA would also consider whether the source's failure to comply with the CAA section 112(d) standard was, in fact, “sudden, infrequent, not reasona bly preventable” and was not instead “caused in part by poor maintenance or careless operation.” 40 C.F.R. § 63.2 (definition of malfunction).

F. What are the testing and initial compliance requirements ? We are proposing that the owner or operator of a new or existing boiler or process heater must conduct performance tests to demonstrate compliance with a ll applicable emission limits. Affected units would be required to conduct the following compliance tests where applicable: (1) Conduct initial and annual stack tests to determine compliance with the PM emission limits using EPA Method 5 or 17

. (2) Conduct initial and annual stack tests to determine compliance with the mercury emission limits using EPA method 29
or ASTM

- D6784

- 02 (Ontario Hydro Metho d ). ( 3 ) Conduct initial and annual stack tests to determine compliance with the HCl emission limits using EPA Method 26 A or EPA Method 26 ( i f no entrained water droplets in the sample ). ( 4 ) Use EPA Method 19 to convert measured concentration values to pound per million Btu values.39 (5) Conduct initial and annual test to determine compliance with the CO emission limits using either EPA Method 10 or a CO CEM S
. (6) Conduct initial and annual test to determine compliance with the D/F emission limits usi ng EPA Method 23. As part of the initial compliance demonstration, we are proposing that you monitor specified operating parameters during the initial performance tests that you would conduct to demonstrate compliance with the PM, mercury, D/F, and HCl

em ission limits. You would calculate the average parameter values measured during each test run over the three run performance test. The average of the t hree average values (depending on the parameter measured) for each applicable parameter would establish the site

- specific operating limit. The applicable operating parameters for which operating limits would be required to be established are based on the emissions limits applicable to your unit as well as the types of add

- on controls on the unit. The foll owing is a summary of the operating limits that would be required we are proposing to be established for the various types of the following units: (1) For boilers and process heaters without wet or dry scrubbers that must comply with an HCl emission limit , you must measure the average chlorine content level in the input fuel(s)40 during the HCl performance test. This is your maximum chlorine input operating limit. ( 2 ) For boilers and process heaters with wet scrubbers, you must measure pressure drop and liquid flow rate of the scrubber during the performance test, and calculate the average value for each test run. The average of the three test run
average s establishes your minimum site

- specific pressure drop and liquid flow rate operating levels. If di fferent average parameter levels are measured during the mercury, PM and HCl tests, the highest of the average values becomes your site

specific operating limit. If you are complying with an HCl emission limit, you must measure pH of the scrubber effluent during the performance test for HCl and determine the average for each test run and the average value for the performance test. This establishes your minimum pH operating limit. ( 3 ) For boilers and process heaters with sorbent injection , you would be r equired to measure the sorbent injection rate during the performance test s for HCl , mercury , and D/F and calculate the average for each test run. The

average of the three test run average s established during the performance test s would be your site

- specif ic minimum sorbent injection rate operating limit. If different sorbents and/or injection rates are measured during the mercury, HCl, and D/F41 tests, the highest of the average values becomes your site

specific operating limit. ( 4 ) For boilers and proc ess heaters with fabric filters in combination with wet scrubbers, you must measure the pH, pressure drop, and liquid flowrate of the wet scrubber during the performance test and calculate the average value for each test run. The minimum test run average establishes your site

specific pH, pressure drop, and liquid flowrate operating limits for the wet scrubber. Furthermore, the fabric filter must be operated such that the bag leak detection system alarm does not sound more than 5 percent of the operating time during any 6

- month period unless a CEMS is installed to measure PM

. ( 5 ) For boilers and process heaters with electrostatic precipitators ( ESP ) in combination with wet scrubbers, you must measure the pH, pressure drop, and liquid flow rate of the w et scrubber during the HCl performance test and you must measure the voltage and current of the ESP collection field s during the mercury and PM performance test. You would then be required to

c alculate the average value of these parameters for each test

r un. The average of the three test run averages would establish your site

- specific minimum pH, pressure drop, and liquid flowrate operating limit for the wet scrubber and the minimum voltage and current operating limits for the ESP.42 ( 6 ) For boilers and p rocess heaters that choose to demonstrate compliance with the mercury emission limit on the basis of fuel analysis and have no add

- on controls or add

- on controls for which you do not want to take credit for any emission reduction of mercury, you would be r equired to measure the mercury content of the inlet fuel that was burned during the mercury performance test. This value is your maximum fuel inlet mercury operating limit. (7) For boilers and process heaters that choose to demonstrate compliance with the HCl emission limit on the basis of fuel analysis and have no add

- on controls or add

- on controls for which you do not want to take credit for any emission reduction of HCl, you would be required to measure the chlorine content of the inlet fuel that wa s burned during the HCl performance test. This value is your maximum fuel inlet chlorine operating limit. These proposed operating limits would not apply to owners or operators of boilers or process heaters having a heat input capacity of less than 10 million Btu per hour (MMBtu/h) or which combust natural gas or refinery gas. Instead, we are proposing that owners or operators of such boilers would be required to and process heaters submit to the delegated authority or EPA, as appropriate, if requested, documentation that a tune

- up meeting43 the requirements of the proposed rule was conducted. We are proposing that, to comply with the work practice standard, a

tune

- up procedure include the following: (1) Inspect the burner, and clean or replace any

comp onents of the burner as necessary, (2) Inspect the flame pattern and make any adjustments to the burner necessary to optimize the flame pattern consistent with the manufacturer’s specifications, (3) Inspect the system controlling the air

- to

- fuel ratio, and ensure that it is correctly calibrated and functioning properly, (4) Minimize total emissions of CO consistent with the manufacturer’s specifications, (5) Measure the concentration in the effluent stream of CO in ppmvd, before and after the adjust ments are made, (6) Submit an annual report containing the concentrations of CO in the effluent stream in ppmvd, and oxygen in percent dry basis, measured before and after the adjustments of the boiler,

a description of any corrective actions taken as a part of the combustion adjustment, and the type and amount of fuel used over the 12 months prior to the annual adjustment. Further, all owners or operators of major source facilities having boilers and process heaters subject to this rule would be44 requir ed to submit to the delegated authority or EPA, as appropriate, documentation that an energy assessment was performed , by qualified personnel, and the cost

- effective energy conservation measures implemented

. i ndentifie d

. The procedures for an energy assess ment are: (1) Conduct a visual inspection of the boiler system. (2) Establish operating characteristics of the facility, energy system specifications, operating and maintenance procedures, and unusual operating constraints, (3) Identify major energy consuming systems, (4) Review available architectural and engineering plans, facility operation and maintenance procedures and logs, and fuel

usage, (5) Identify a list of major energy conservation measures, (6) Determine the energy savings potential of the energy conservation measures identified, and (7) Prepare a comprehensive report detailing the ways to improve efficiency, the cost of specific improvements, benefits, and the time frame for recouping those investments , and

. (8) Implement each c ost

- effective energy conservation measure identified.
G. What are the continuous compliance requirements ?45 To demonstrate continuous compliance with the emission limitations, we are proposing following requirements : (1 ) For units combusting coal, biomass , or residual fuel oil (i.e., No 4, 5 or 6 fuel oil) with heat input capacities of less than 250 million Btu per hour that do not use a wet scrubber, we are proposing that opacity levels be maintained to less than 1 0 percent ( daily average) for existing an d new units with applicable emission limits. Or, if the unit is controlled with a fabric filter, instead of continuous monitoring opacity, the fabric filter must be continuously operated such that the bag leak detection system alarm does not sound more th an 5 percent of the operating time during any 6

- month period (unless a PM CEMS is used)

. (2) For units combusting coal, biomass, or residual oil with heat input capacities of 250 million Btu per hour or greater, we are proposing that PM CEMS be installed a nd o perated and that PM levels (monthly average) be maintained below the applicable PM limit

. (3) For boilers and process heaters with wet scrubbers, we are proposing that you monitor pressure drop and liquid flow rate of the scrubber and maintain the 12

- h our block averages at or above the operating limits established during the performance test. You must monitor the pH of the scrubber and maintain the46

12

- hour block average at or above the operating limit established during the performance test to demonstr ate continuous compliance with the HCl emission limits. (4) For boilers and process heaters with dry scrubbers, we are proposing that you continuously monitor the sorbent injection rate and maintain it at or above the operating limits established during th e performance tests. (5) For boilers and process heaters having heat input capacities of less than 250 million Btu per hour with an ESP in combination with a wet scrubber, we are proposing that you monitor the pH, pressure drop, and liquid flow rate of the wet scrubber and maintain the 12

- hour block averages at or above the operating limits established during the HCl performance test and that you monitor the voltage and current of the ESP collection plates and maintain the 12

- hour block averages at or above the operating limits established during the mercury or PM performance test. (6) For units that choose to comply with either the mercury emission limit or the HCl emission limit based on fuel analysis rather than on performance stack testing, we are propos ing that you maintain daily fuel records that demonstrate that you burned no new fuels or fuels from a new supplier such that the mercury content or the chlorine content of the inlet fuel was maintained47 at or below your maximum fuel mercury content operati ng limit or your chlorine content operating limit set during the performance stack tests. If you plan to burn a new fuel, a fuel from a new mixture, or a new supplier’s fuel that differs from what was burned during the initial performance tests, then you must recalculate the maximum mercury input and/or the maximum chlorine input anticipated from the new fuels based on supplier data or own fuel analysis , using the methodology specified in Table 6 of this proposed rule . If the results of recalculating the inputs exceed the average content levels established during the initial test then , you must conduct a new performance

test (s) to demonstrate continuous compliance with the applicable emission limit. (7) For all boilers and process heaters, we are proposing that you maintain daily records of fuel use that demonstrate that you have burned no materials that are considered solid

waste. ( 8 ) For boilers and process heaters in any of the subcategories with heat input capacities greater than 100

MMBtu / h , we are p roposing that you continuously monitor CO and maintain the average CO emissions at or below the applicable limit listed in Table s 1 or 2 of this proposed rule

.48
If an owner or operator would like to use a control device other than the ones specified in thi s section to comply with th is proposed rule, the owner/operator should follow the requirements in 40 CFR 63.8(f), which presents the procedure for submitting a request to the Administrator to use alternative monitoring

. H. What are the notification, recor dkeeping and reporting requirements ? All new and existing sources would be required to comply with certain requirements of the General Provisions (40 CFR part 63, subpart A), which are identified in Table 10 of this proposed rule. The General Provisions i nclude specific requirements for notifications, recordkeeping, and reporting. Each owner or operator would be required to submit a notification of compliance status report, as required by §63.9(h) of the General Provisions. T h is proposed rule would requir e the owner or operator to include in the notification of compliance status report certifications of compliance with rule requirements. Semiannual compliance reports, as required by §63.10(e)(3) of subpart A, would be required only for semiannual reporting periods when a deviation from any of the requirements in the49
rule occurred , or any process changes occurred and compliance certifications were reevaluated. Th is proposed rule would require records to demonstrate compliance with each emission limit and wor k practice standard

. These recordkeeping requirements are specified directly in the General Provisions to 40 CFR part 63 , and are identified in Table 10. O wner s or operator s of sources with units with heat input capacity of less than 10 MMBtu/h or units combusting natural gas or refinery gas must keep records of the dates and the results of each required boiler tune

- up . Records of either continuously monitored parameter data for

a control device if a device is used to control the emissions or CEMS data wo uld be required. We are proposing that y ou must keep the following records: (1) All reports and notifications submitted to comply with th is proposed rule. (2) Continuous monitoring data as required in th is proposed rule. (3) Each instance in which y ou did not meet each emission limit and each operating limit (i.e., deviations from th is proposed rule). (4) Daily hours of operation by each source.50 (5) Total fuel use by each affected source electing to comply with an emission limit based on fuel ana lysis for each 30

- day period along with a description of the fuel, the total fuel usage amounts and units of measure, and information on the supplier and original source of the fuel. (6) Calculations and supporting information of chlorine fuel input, as required in th is proposed rule , for each affected source with an applicable HCl emission limit

. (7) Calculations and supporting information of mercury fuel input, as required in th is proposed rule, for each affected source with an applicable mercury emis sion limit. (8) A signed statement, as required in th is proposed rule, indicating that you burned no new fuel type and no new fuel mixture or that the recalculation of chlorine input demonstrate d that the new fuel or new mixture still meets chlorine fuel input levels , for each affected source with an applicable HCl emission limit. (9) A signed statement, as required in th is proposed rule, indicating that y ou burned no new fuels and no new fuel mixture

or that the recalculation of mercury fuel input d emo nstrate d that the new fuel or new fuel mixture still meets the mercury fuel input levels , for each affected source with an applicable mercury emission limit.51 (1 0 ) A copy of the results of all performance tests, fuel analysis, opacity observations, perfor mance evaluations, or other compliance demonstrations conducted to demonstrate initial or continuous compliance with th is proposed rule. (1 1 ) A copy of your site

- specific monitoring plan developed for th is proposed rule as specified in 63 CFR 63.8(e) , if applicable. We are also proposing to require that y ou submit the following reports and notifications: (1) Notifications required by the General Provisions. (2) Initial Notification no later than 120 calendar days after you become subject to this subp art. (3) Notification of Intent to conduct performance tests and/or compliance demonstration at least 60 calendar days before the performance test and/or compliance demonstration is scheduled. (4) Notification of Compliance Status 60 calendar days foll owing completion of the performance test and/or compliance demonstration. (5) Compliance reports semi

- annually.

I. Submission of Emissions Test Results to EPA The EPA must have performance test data to conduct effective reviews of CAA Section 112 and 1 29 standards, as well52 as for many other purposes , including compliance determinations, emissions factor development, and annual emissions rate quantification. determinations. In conducting these required reviews, we have found it burdensome ineffective and time consuming not only for us but also for regulatory agencies and source owners and operators to locate, collect, and submit emissions test data because of varied locations for data storage and varied data storage methods. One improvement that has

occur red in recent years is the availability of stack test reports in electronic format as a replacement for cumbersome paper copies. In this action, we are taking a step to improve data accessibility. Boiler Owners and operators of boilers and

process heater facilities heaters will be required to submit to an EPA electronic database , the Electronic Reporting Tool (ERT), an electronic copy of reports of certain performance tests required under this rule. Data entry will be through an electronic emissions test r eport structure called the Electronic Reporting Tool (ERT) that will be used by the staff as part of the emissions testing project. The ERT was developed with input from stack testing companies who generally collect and compile performance test data elect ronically and offices within State , and local , and Tribal agencies which perform field test53

assessments. The ERT is currently available , and access to direct data submittal to EPA’s electronic emissions database (WebFIRE) will become available by Decembe r 31, 2011. Please note that the The requirement to submit source test data electronically to EPA will not require any additional performance testing

. and will apply to those performance tests conducted using test methods that are supported by ERT. The ERT contains a specific electronic data entry form for most of the commonly used EPA reference methods. However, at this time, the ERT does not have a form for every performance test method, so the ERT structure also includes a spreadsheet function for those methods not currently supported. For more information, see the website link below. We The website listed below contains a listing of the pollutants and test methods supported by ERT. In addition, when a facility submits performance test data to WebFIRE, there will be no additional requirements for emissions test data compilation. Moreover, we believe industry will benefit from development of improved emissions factors, fewer follow

- up information requests, and better regulation development , as discussed below as discussed below. The information to be reported is already required for the existing test methods and is necessary to evaluate the conformance to the test method

.54 As mentioned above, the information to be reported is already required by the exi sting test methods and is necessary to evaluate the conformance to the test method. One major advantage of submitting source test data through the ERT is that it provides a standardized method to compile and store much of the documentation required to be r eported by this rule while clearly stating what testing information we require. Another important benefit of submitting these data to EPA at the time the source test is conducted is that it will substantially reduce the effort involved in data collection a ctivities in the future. Specifically, because EPA would already have adequate source category data to conduct residual risk assessments or technology reviews, there would be fewer or less substantial data collection requests ( e.g., CAA Section 114 letter s). This results in a reduced burden on both affected facilities (in terms of reduced manpower to respond to data collection requests) and EPA (in terms of preparing and distributing data collection requests). State/local/Tribal agencies may also benefi t in that their review may be more streamlined and accurate as the States will not have to re

- enter the data to assess the calculations and verify the data entry . Finally, another benefit of submitting these data to WebFIRE electronically is that these da ta will Formatted: Font color: Black55 improve greatly the overall quality of the existing and new emissions factors will benefit by supplementing the pool of emissions test data upon which the emissions factor is based and by ensuring that data are more representative of current indust ry operational procedures. A common complaint we hear from industry and regulators is that emissions factors are outdated or not representative of a particular source category. Receiving the and incorporating data from for most performance tests will ensur e that emissions factors, when updated with these data , represent accurately the most current operational practices. In summary, receiving test data already collected for other purposes and using them in the emissions factors development program will save industry, State/local/Tribal agencies, and EPA time and money and work to improve the quality of emissions inventories and related regulatory decisions

. As mentioned earlier, the electronic data base that will be used is EPA’s WebFIRE, which is a Web site accessible through EPA’s Technology Transfer Network (TTN). The WebFIRE Web site was constructed to store emissions test data for use in developing emissions factors. A description of the WebFIRE data base can be found at http://cfpub.epa.gov/ oarweb/index.cfm?action=fire.main.56 The ERT will be able to transmit the electronic report through EPA’s Central Data Exchange (CDX) network for storage in the WebFIRE database. data base. Although ERT is not the only electronic interface that can be used to submit source test data to the CDX for entry into WebFIRE, it makes submittal of data very straightforward and easy. A description of the ERT can be found at http://www.epa.gov/ttn/chief/ert/ert

_ tool.html. Finally, a listing of the pollutants and test methods supported by ERT are also available on the web page listed above.

**I V**  **. Rationale for**  **th is**  **Proposed Rule**

A. How did EPA determine which sources would be regulated under th is proposed rule ? Th is proposed rule regulates source categories covering industrial boilers, institutional and commercial boilers, and process heaters. These source categories potentially include combustion units that are already regulated by other MACT standards under CAA sections 112 or 129 . Ther efore, we are excluding from t hi s proposed rule any units that are subject to regulation in another MACT standard established under CAA section 112 or a standard established under CAA section 129. The CAA specifically requires that fossil fuel

- fired steam generating units of more than 25 megawatts that produce electricity for sale (i.e., utility boilers) be reviewed57 separately by EPA. Consequently, th is proposed rule would not regulate fossil fuel

- fired utility boilers greater than 25 megawatts, but would regulate fossil fuel

- fired units less than 25 megawatts and all utility boilers firing a non

- fossil fuel that is not a solid waste.

T he scope of the process heater source category i s limited to only indirect

- fired units 2

The proposed rule would not regulate hot water heaters, as defined in this proposed rule, because such units are not part of the listed source categories. Many industrial facilities have office buildings located onsite which use hot water heaters. Suc h hot water heaters, by their design and operation, could be considered boilers since hot water heater s meet the . Direct

- fired units are covered in other MACT standards or rulemakings pertaining to industrial process operations. For example, lime kilns are covered by the Pulp and Paper NESHAP (40 CFR p art 63, subpart S). Indirect

fired process heaters are similar to boilers in fuel use, emissions , and applicable controls, and, therefore, it is appropriate for EPA to combine this listed source category of units with the listed sources categories of industrial boilers and commercial / institutional boilers for purposes of developing emission standards

.

2 Indirect

- fired process heaters are combustion devices in which the combustion gases do not directly come into cont act with process materials.58 definition of a boiler as specified in the proposed rule

. However , because they are enclosed devices that combust fuel for the purpose of reco very energy to heat water. However, hot water heaters are more appropriately described as residential

type boilers, not industrial, commercial or institutional boilers because their output (i.e., hot water) is intended for personal use rather than for use in an industrial, commercial, or institutional process

. Moreover , since hot water heaters generally are small and use natural gas as fuel, their emissions are negligible compared to the emissions from the industrial operations that make such facilities m ajor sources, and compared to boilers that are used for industrial, commercial, or institutional purposes. Moreover, hot water heaters are more appropriately described as residential

- type boilers, not industrial, commercial or institutional boilers becaus e their output (i.e., hot water) is intended for personal use rather than for use in an industrial, commercial, or institutional

process . However, the primary reason that we are excluding hot water heaters is that hot water heaters are not part of the lis ted source category. Consequently, we are including a definition of hot water heaters that includes fuel, size, pressure and temperature limitations that we believe are59 appropriate to distinguish between residential

- type units and industrial, commercial o r ins titutional units. The CAA allows EPA to divide source categories into subcategories based on differences in class, type, or size. For example, differences between given types of units can lead to corresponding differences in the nature of emissions and the technical feasibility of applying emission control techniques. The design, operating, and emissions information that EPA has reviewed indicates differences in unit design that distinguish different types of boilers. Data indicate that there are

s ignificant design and operational differences between units that burn coal, biomass , liquid and gaseous fuels. Boiler systems are designed for specific fuel types and will encounter problems if a fuel with characteristics other than those originally speci fied is fired. While many boilers in the population database are indicated to co

- fire liquids or gases with solid fuels, in actuality most of these commonly use fuel oil or natural gas as a startup fuel only , and operate on solid fuel during the remainder of their operation. In contrast, some co - fired units are specifically designed to fire combinations of solids, liquids, and gases. Changes to the fuel type would generally require extensive changes to the fuel handling and feeding system (e.g., a stoker using wood as fuel60 would need to be redesigned to handle fuel oil or gaseous fuel). Additionally, the burners and combustion chamber would need to be redesigned and modified to handle different fuel types and account for increases or decreases in the fue l volume. In some cases, the changes may reduce the capacity and efficiency of the boiler or process heater. An additional effect of these changes would be extensive retrofitting needed to operate using a different fuel

. The design of the boiler or proc ess heater, which is dependent in part on the type of fuel being burned, impacts the degree of combustion. Boilers and process heaters emit a number of different types of HAP emissions. Organic HAP are formed from incomplete combustion and are influenced by the design and operation of the unit. The degree of combustion may be greatly influenced by three general factors: time, turbulence, and temperature. On the other hand, the formation of fuel dependent HAP (metals, mercury, and acid gases) is depende nt upon the composition of the fuel. These fuel dependent HAP emissions generally can be controlled by either changing the fuel property before combustion or by removing the HAP from the flue gas after combustion. We first examined the HAP emissions resu lts to determine if subcategorization by unit design type was warranted. We61 concluded that the data were sufficient for determining that a distinguishable difference in performance exists based on unit design type. Therefore, b ecause different types of u nits have different emission characteristics which may influence the feasibility of effectiveness of emission control, they should be regulated separately (i.e., subcategorized). Accordingly, we decided propose to subcategorize boilers and process heaters based on unit design in order to account for these differences in emissions and applicable controls. For the fuel

- dependent HAP (metals, mercury, acid gases), we identified f ive basic unit types as subcategories. These are the following: (1) units design ed to burn coal, (2) units designed to burn biomass, (3) units designed to burn liquid fuel, (4) units designed to burn natural gas/refinery gas, and (5) units designed to burn other process gases. Within the basic unit types the re are different designs a nd combustion systems, while having a minor effect on fuel

- related HAP emissions, that have a much larger effect on organic HAP emissions. Therefore, we decided to further subcategorize based on these different unit designs but only in proposing standards for organic HAP emissions. We have identified the following 1 0 subcategories for organic HAP : Pulverized coal units,62 Stokers designed to burn coal, Fluidized bed units designed to burn coal, Stokers designed to burn biomass, Fluidized bed units desi gned to burn biomass, Suspension burners/Dutch Ovens designed to burn biomass, Fuel Cells designed to burn biomass, Units designed to burn liquid fuel, Units designed to burn natural gas/refinery ga s, and Units designed to burn other gases

. These sub categories are based on the primary fuel that the boiler or process heater is designed to burn. We are aware that some boilers burn a combination of fuel types or burn a different fuel type as a backup fuel if the primary fuel supply is curtailed. Howeve r, boilers are designed based on the primary fuel type (and perhaps to burn a backup fuel) and can encounter operational problems if another fuel type that was not considered in its design is fired at more than 10 percent of the heat input to the boiler. Also, in some cases, a small amount of coal may be added to a biomass designed boiler to stabilize the combustion when the biomass has a higher moisture content than normal. In this case, it would not be appropriate to classify the boiler as being in one of the “coal” subcategories because the boiler design is such that it is constructed and63 operated to combust biomass, and could not combust primarily coal (without significant retrofitting or design changes)

. Therefore, we are proposing to define boilers and process heaters that burn more than 10 percent coal (on an annual heat input basis) as being in one of the coal subcategories. We are also proposing to define boilers and process heaters that burn more than 10 percent biomass, and less than 10 percent coal, (on an annual heat input basis) as being in one of the biomass subcategories. We are proposing to define boilers and process heaters that burn more than 10 percent liquid fuel, and less than 10 percent solid fuel, (on an annual heat input basis) as being in the liquid subcategory. We are proposing to define boilers and process heaters that burn more than 90 percent natural gas and/or refinery gas (on an annual heat input basis) as being in the Gas 1 subcategory. This would ensure that each boiler and process heater is subject to emissions standards calculated on the basis of the best performing units with similar design and operation. The remaining boilers and process heaters, except for those described below would be in the Gas 2 subcategory.

In addition, there is a certain class of natural gas

- fired

p rocess heaters that are designed and operate d in such a manner that are different compared to typical process heaters. A64 review of information gathered on process heaters used in the metal processi ng industries shows that these process heaters typically are designed with multiple burners that fired into individual combustion chambers

. These i ndividual burners are operated to cycle on and off to maintain the proper temperatures throughout the variou s zones of the process heater. Thus, due to their design, these process heaters rarely operate in a steady

- state condition due to burners constantly starting up and shutting down resulting in emissions characteristics different from the process heaters us ed in other industries . The process heaters used in metal processing are natural gas

- fired and include annealing furnaces, preheat furnaces, reheat furnaces, aging furnaces, and heat treat furnaces

. Therefore, we have identified propose to i dentif y these metal processing process heaters (furnaces) as a separate eleventh subcategory. In summary, we have identified 11 subcategories of boilers and process heaters located at major sources.

B. How did EPA select the format for th is proposed rule ? Th is propo sed rule includes numerical emission limits for PM, mercury, HCl , CO , and D/F . The selection of numerical emission limits as the format for th is proposed rule provides flexibility for the regulated community by allowing a regulated source to choose any co ntrol technology or technique to meet the65 emission limits, rather than requiring each unit to use a prescribed control method that may no t be appropriate in each

case.
We are proposing numerical emission rate limits as a mass of pollutant emitted per heat energy input to the boiler or process heater for the fuel

- related HAP . The most typical units for the limits are pounds of pollutant emitted per million Btu of heat input. The mass per heat input units are consistent with other Federal and many State bo iler regulations 3

We are proposing outlet concentration as the format for the organic HAP . An outlet concentration limit for organic HAP would also be consistent with the format of other regulations. and allows easy comparison between such requirements. Additionally, th is proposed rule contains an option to monitor inlet chlorine and mercury content in the fuel to meet outlet emission rate limits. This option can only be done on a m ass basis.

Boilers and process heaters can emit a wide variety of

compo unds, depending on the fuel burned. Because of the large number of HAP potentially present and the disparity in the quantity and quality of the emissions information available, EPA grouped the HAP into f ive categories: mercury, non

- mercury metallic HAP, inorganic HAP, non - dioxin organic HAP , an d D/F

.

3 For example, the new source performance standards for industrial, commercial, and institutional steam generating units (40 CFR subpart Db) have emission limits for sulfur dioxide, nitrogen oxide, and PM in terms of pounds per million Btu.66

T he pollutants within each group have similar characteristics and can be controlled with the same techniques. For example,

non - mercury metallic HAP can be controlled with PM controls. We chose to look at m ercury separately from other metallic HAP due to its different chemical characteristics and its different control technology feasibility

. Next, EPA identified compounds that could be used as surrogates for all the compounds in each pollutant category.

Fo r the non

- mercury metallic HAP, we chose to use PM as a surrogate. Most, if not all, non

- mercury metallic HAP emitted from combustion sources will appear on the flue gas fly

- ash. Therefore, the same control techniques that would be used to control the fl y - ash PM will control non

- mercury metallic HAP.

P M was also chosen instead of specific metallic HAP because all fuels do not emit the same type and amount of metallic HAP but most generally emit PM that includes some amount and combination of metallic HAP . The use of PM as a surrogate will also eliminate the cost of performance testing to comply with numerous standards for individual non - mercury metals. Since

non - mercury metallic HAP tend to be on small size particles (i.e., fine particle enrichment), we considered using PM 2.5 as the surrogate but we determined that PM (filterable) was the more appropriate surrogate since, based on the emission data67 obtained during the information collection effort, the majority of the PM emitted from well controlled unit s is fine particulate (PM 2.5 ). However for two reasons. First , the test method (OTM 27) for measuring PM 2.5 is only applicable for use in exhaust stacks without entrained water droplets. Therefore, the test method (OTM 27) for measuring PM 2.5 is not appl icable for units equipped with wet scrubbers which will likely be required necessary to achieve the proposed HCl emission limits. Second, based on the emission data obtained , during EPA’s information collection effort, from units not equipped with wet

scru bbers, the majority of the filterable PM emitted from units that are well controlled for PM is fine particulate (PM 2.5 ). Thus, we are proposing to use PM , (filterable) , instead of PM 2.5 , as the surrogate for non

- mercury metals. For inorganic HAP, EP A is proposing us ing HCl as a surrogate. The emissions test information available to EPA indicate that the primary inorganic HAP emitted from boilers and process heaters are acid gases, with HCl present in the largest amounts. Other inorganic compounds e mitted are found in much smaller quantities. C ontrol technologies that reduce HCl also control other inorganic compounds that are such as chlorine and other acid gases. Thus, the best controls for HCl would also be the best controls for other inorganic HA P that are acid gases.68 Therefore, HCl is a good surrogate for inorganic HAP because controlling HCl will result in control of other inorganic HAP emissions. For organic HAP, we considered both THC and C O as a surrogate for non - dioxin organic HAP emitted from boilers and process heaters . CO has generally been used as a surrogate for organic HAP because CO is a good indicator of incomplete combustion and organic HAP are products of incomplete combustion. However, based on concern s that CO may not be an

ap propriate surrogate for D/F because , unlike other organic HAP, D/F can be formed outside the combustion unit, we are proposing

to us e CO as a surrogate for non

- di o xin organic HAP . We are also proposing a separate emission limits for D/F. For non

dioxin o rganic HAP, using CO as a surrogate is a reasonable approach because minimizing CO emissions will result in minimizing non

- d ioxin organic HAP. Methods used for the control of non - dioxin organic HAP emissions would be the same methods used to control CO em issions. These emission control methods include achieving good combustion or using an oxidation catalyst

. Standards limiting emissions of CO will also result in decreases in non - dioxin organic HAP emissions (with the additional benefit of decreasing vola tile organic compounds ( VOC ) emissions). Establishing emission limits for specific69 organic HAP (with the exception of D/F) would be impractical and costly. C O , which is less expensive to test for and monitor, is appropriate for use as a surrogate for non - dioxin organic HAP. The Agency recognizes that the level and distribution of organic HAP as sociated with CO emissions will vary from unit to unit

. Fo r example, the principal organic HAP emitted from coal

fired units is benzene accounting for 20 percent o f the organic HAP while the principal organic HAP emitted from biomass

- fired units is formaldehyde accounting for 34 percent of the organic

HAP. Limiting CO as a surrogate for only non - dioxin organic HAP will eliminate costs associated with speciating num erous compounds. The proposed standards establish separate emission limits for D/F because of the high toxicity associated with even low masses of these compounds.

T HC c ould also be an appropriate surrogate for non

- dioxin organic HAP because low THC also ensures good combustion efficiency and, thus, low organic HAP. However, w e believe CO is preferable because many sources currently have CO CEMS. In addition, there are more CO emission data available for the various subcategories than THC emission data. EPA’s Office of Research and Development (ORD) is currently conducting research on surrogates for the Utility MACT rulemaking and ORD findings will be considered in th e final rulemaking.70

C. How did EPA determine the proposed emission limitations for exi sting units ? All standards established pursuant to CAA section 112(d)(2) must reflect MACT, the maximum degree of reduction in emissions of air pollutants that the Administrator, taking into consideration the cost of achieving such emissions reductions,

a nd any nonair quality health and environmental impacts and energy requirements, determined is achievable for each category. For existing sources, MACT cannot be less stringent than the average emission limitation achieved by the best performing 12 percent of existing sources for categories and subcategories with 30 or more sources or the best performing 5 sources for subcategories with less than 30 sources . This requirement constitutes the MACT floor for existing boilers and process heaters. However, EPA may not consider costs or other impacts in determining the MACT floor. EPA must consider cost, nonair quality health and environmental impacts, and energy requirements in connection with any standards that are more stringent than the MACT floor (beyond

- t he

- floor controls).

D. How did EPA determine the MACT floor for existing units ? EPA must consider available emissions information to determine the MACT floor. We calculated the MACT floor for a subcategory of sources by ranking all the available emission s71
data from units within the subcategory from lowest emissions to highest emissions, and then taking the numerical average of the test results from the best performing (lowest emitting) 12 percent of sources. The We first considered whether fuel switching would be an appropriate control option for sources in each subcategory. We considered the feasibility of fuel switching to other fuels used in the subcategory and to fuels from other subcategories. This consideration included determining whether switchin g fuels would achieve lower HAP emissions. A second consideration was whether fuel switching could be technically achieved by boilers and process heaters in the subcategory considering the existing design of boilers and process heaters. We also considere d the availability of various types of fuel. After considering these factors, we determined that fuel switching was not an appropriate control technology for purposes of determining the MACT floor level of control for any subcategory. This decision was ba sed on the overall effect of fuel switching on HAP emissions, technical and design considerations discussed previously in this preamble, and concerns about fuel availability. Based on the data available in the emissions database, we determined that while f uel switching from solid fuels to gaseous72 or liquid fuels would decrease PM and some metals emissions, emissions of some organic HAP would increase. This determination is discussed in the memorandum “ Development of Fuel Switching Costs and Emission Reduct ions for Industrial, Commercial, and Institutional Boilers and Process Heaters National Emission Standards for Hazardous Air Pollutants ” located in the docket. A similar determination was made when considering fuel switching to cleaner fuels within a subca tegory. For example, the term “ clean coal ” refers to coal that is lower in sulfur content and not necessarily lower in HAP content. Data gathered by EPA also indicates that within specific coal types HAP

content can vary significantly. Switching to a lo w sulfur coal may actually increase emissions of some HAP. Therefore, it is not appropriate for EPA to include fuel switching to a low sulfur coal as part of the MACT standards for boilers and process heaters. Fuel switching from coal to biomass would

re sult in similar impacts on HAP emissions. While this would reduce metallic HAP emissions, it would likely increase emissions of organics based on information in the emissions database. Another factor considered was the availability of alternative fuel t ypes. Natural gas pipelines are not available73 in all regions of the U.S., and natural gas is simply not available as a fuel for many industrial, commercial, and institutional boilers and process heaters. Moreover, even where pipelines provide access to n atural gas, supplies of natural gas may not be adequate. For example, it is common practice in cities during winter months (or periods of peak demand) to prioritize natural gas usage for residential areas before industrial usage. Requiring boilers and pr ocess heaters to switch to natural gas would place an even greater strain on natural gas resources. Consequently, even where pipelines exist, some units would not be able to run at normal or full capacity during these times if shortages were to occur. The refore, under any circumstances, there would be some units that could not comply with a requirement to switch to natural

gas. Similar problems for fuel switching to biomass could arise. Existing sources burning biomass generally are combusting a recovered material from the manufacturing or agriculture

process. Industrial, commercial, and institutional facilities that are not associated with the wood products industry or agriculture may not have access to a sufficient supply of biomass materials to replace their fossil fuel.74 As discussed previously in this preamble, there is a significant concern that switching fuels would be infeasible for sources designed and operated to burn specific fuel types. Changes in the type of fuel burned by a boiler or process heater (solid, liquid, or gas) may require extensive changes to the fuel handling and feeding system ( e.g. , a stoker using wood as fuel would need to be redesigned to handle fuel oil or gaseous fuel). Additionally, burners and combustion chamber designs a re generally not capable of handling different fuel types, and generally cannot accommodate increases or decreases in the fuel volume. Design changes to allow different fuel use, in some cases, may reduce the capacity and efficiency of the boiler or

proce ss heater. Reduced efficiency may result in less complete combustion and, thus, an increase in organic HAP emissions. For the reasons discussed above, we decided that fuel switching to cleaner solid fuels or to liquid or gaseous fuels is not an appropria te criteria for identifying the MACT floor level of control for units in the boilers and process heaters category. The refore, the MACT floor limits for each of the HAP and HAP surrogates ( PM, mercury, CO , HCl, and D/F ) are calculated based on the performa nce of the lowest emitting (best performing) sources in each of the subcat eg ories

. We ranked all of the sources for which we had data based on their emissions75
and identified the lowest emitting 12 percent of the sources for each HAP

. W e used the emissions data for those best performing affected sources to determine the emission limits to be proposed, with an accounting for variability. EPA must exercise its judgment, based on an evaluation of the relevant factors and available data, to determine the level of emissions control that has been achieved by the best performing sources under variable conditions. The DC Circuit Court of Appeals has recognized that EPA may consider variability in estimating the degree of emission reduction achieved by best

- perform ing sources and in setting MACT floors. See Mossville Envt’l Action Now v. EPA, 370 F.3d 1232, 1241

– 42 (D.C. Cir 2004) (holding EPA may consider emission variability in estimating performance achieved by best

performing sources and may set the floor at le vel that best

performing source can expect to meet “ every day and under all operating conditions ” ). In determining t he MACT floor limit s, we first determine the floor, which is the level achieved in practice by the average of the top 12 percent. We the n assess variability of the best performers by using a statistical formula designed to estimate a MACT floor level that is achievable by the average of the best performing sources if the best performing sources were76 able to replicate the compliance tests i n our data base. Specifically, the MACT floor limit is an upper prediction limit (U P L) calculated with the Student’s t

- test using the TINV function in Microsoft Excel . The Student’s t

- test has also been used in other EPA rulemakings (e.g., NSPS for Hospi tal/Medical/Infectious Waste Incinerators) in accounting for variability. A prediction interval for a future observation is an interval that will, with a specified degree of confidence, contain the next (or some other pre

- specified) randomly selected obse rvation from a population. In other words, the prediction interval estimates what future values will be, based upon present or past background samples taken. Given this definiti on, the UPL represents the value which we can expect the mean of 3 future obs ervations (3

- run average) to fall below, based upon the results of a independent sample from the same population. In other words, if we were to randomly select a future test condition from any of these sources (i.e., average of 3 runs), we can be 99% conf ident that the reported level will fall at or below the U P L value. To calculate the U P L, we used the average (or sample mean) and sample standard deviation, which are two statistical measures calculated from the sample data. The average is the central va lue of a data set, and the77 standard deviation is the common measure of the dispersion of the data set around the average. We first determined the distribution of the emissions data for the best

- performing 12 percent of units within each subcategory prior t o calculating UPL values. To evaluate the distribution of the best performing dataset, we first computed the skewness and kurtosis statistics and then conducted the appropriate small

- sample hypothesis tests. The skewness statistic (S) characterizes the de gree of asymmetry of a given data distribution. Normally distributed data have a skewness of 0. A skewness statistic that is greater (less) than 0 indicates that the data are asymmetrically distributed with a right (left) tail extending towards positive (negative) values. Further, the standard error of the skewness statistic (SES) is given by SES = SQRT(6/N) where N is the sample size. According to the small sample skewness hypothesis test, if the skewness statistic (S) is greater than two times the SES , the data distribution can be considered non

- normal. The kurtosis statistic (K) characterizes the degree of peakedness or flatness of a given data distribution in comparison to a normal distribution. Normally distributed data have a kurtosis of 0. A kur tosis statistic that is greater (less) than 0 indicates a relatively peaked (flat) distribution.78 Further, the standard error of the kurtosis statistic (SEK) is given by SEK = SQRT(24/N) where N is the sample size. According to the small sample kurtosis hy pothesis test, if the kurtosis statistic (K) is greater than two times the SEK, the data distribution is typically considered to be non

- normal. We applied t he skewness and kurtosis hypothesis tests to both the reported test values and the lognormal values of the reported test values. If the s kewness (S) and kurtosis (K) statistics of the reported data set were both less than tw ice the SES and SEK, respectively , the dataset was classified as normally distributed. I f neither of the skewness (S) and kurtosis (K) statistics, or only one of the se statistics were less than tw ice the SES or SEK, respectively, then the skewness and kurtosis hypothesis tests were conducted for the natural log

- transformed data. Then the distribution most similar to a normal distrib ution was selected as the basis for calculating the UPL. If both the reported values and the natural

- log transformed reported values had skewness (S) and kurtosis (K) statistics that were greater than twice the SES or SEK, respectively, the normally distr ibuted dataset was selected as the basis of the floor to be conservative. If the results of the skewness and kurtosis hypothesis tests were mixed for the reported values and the natural log

- transformed reported values,79
we also chose the normal distributio n to be conservative. We believe this approach is more accurate and obtained more representative results than a more simplistic normal distribution assumption. We calculated the 99 percent U P L values (which was determined to be the appropriate percentile to use in setting MACT limits in the Hospital/Medical/Infectious Waste Incinerators NSPS) using the following Microsoft Excel equations , based on the test run data for those units in the best

- performing 12 percent: Since the compliance with the MACT floor emission limit is based on the average of a three run test, the UPL is calculated by:

Where: n = the number of test runs m = the num ber of test runs in the compliance average This calculation was performed using the following two Excel functions: Normal distribution: 99% UPL = AVERAGE(Test Runs in Top 12%) + [STDEV(Test Runs in Top 12%) x TINV(2 x probability, n

- 1 degrees of freedom )], )*SQRT((1/n)+(1/3))], for a one

- tailed t

- value (with 2 x probability), probability of 0.01, and sample size of n Lognormal distribution: 99% UPL = EXP{AVERAGE(Natural Log Values of Test Runs in Top 12%) + [STDEV(Natural Log Values of Test Runs in To p 12%) x TINV(2 x probability, n

- 1 degrees of Formatted: Line spacing: single80
freedom )]}, )* SQRT((1/n)+(1/3))]}, for a one

- tailed t

- value (with 2 x probability), probability of 0.01, and sample size of n

We are requesting comment on whether there is a more appropriate statistical appro ach to account for variability in the MACT floor analyses when there are emission data from a limited number of units in the subcategory. However, after review of the available HAP data, including both emission test data and fuel analyses , we determined t hat it was inappropriate to use only this MACT floor approach to determine variability and to establish emission limits for boilers and process heaters , because this approach considers only the emissions test data . The main problem with using only the HAP emissions test data is that the data, which

may reflect the variability of fuel

- related HAP of the best performing units , may not reflect the variability of fuel

related HAP from the best performing units over the long term. Based on our current informat ion Based on fuel

- related HAP concentrations (nine individual samples collected over a 30

- day period) obtained, p ursuant to letters mandating data gathering issued under the authority of CAA section 114 , fuel

- related HAP levels in the various fuels can vary significantly over time

. Formatted81 The first step in establishing a MACT standard is to determine the MACT floor. A necessary step in doing so is determining the amount of HAP emitted. In the case of fuel

related HAP emitted, this is not necessarily a straight forward undertaking. Single stack measurements represent a snapshot in time of a source’s emissions, always raising questions of how representative such emissions are of the source’s emissions over time. The variations in fuel

- related HAP inputs directly translate to a variability of fuel

- related HAP stack emissions.

W e believe that single short term stack test data (typically a few hours) are probably not indicative of long term emissions performance, and so are not the best indicator s of performance ov er time. With these facts in mind, we carefully considered alternatives other than use of only single short

- term stack test results to quantify performance for fuel

- related HAP

. W e decided that the most accurate method available to us to determine long t erm fuel

- related HAP emissions performance was

to obtain use data on the fuel

- related HAP inputs in the fuels used by the best performing units

. Pursuant to letters mandating data gathering, issued , obtained as part of our information collection effort und er the authority of CAA section 114, we obtained on long

- term fuel

- related HAP concentrations ( nine individual samples collected over a 30

- day period) in each82 fuel, along with the fuel

- related HAP concentrations during the stack tests

. As previously discus sed above, we account for variability in setting floors, not only because variability is an element of performance, but because it is reasonable to assess best performance over time. Here, for example, we know that the HAP emission data from the best perf orming units are short

- term averages, and that the actual HAP emissions from those sources will vary over time. If we do not account for this variability, we would expect that even the unit s that perform better than the floor on average would potentially exceed the floor emission levels a significant part of the time which would mean that variability was not properly taken into account

. This variability includes the day

- to

- day variability in the total fuel

- related HAP input to each unit and variability of the sampling and analysis methods, and it includes the variability resulting from site

- to

- site differences for the best performing units

. We c alculated the MACT floor based on the UPL (upper 99th percentile) as described earlier from the average performa nce of the best performing units , Students t

- factor, and the total variability of the best performing units

. This approach reasonably ensures that the emission limit selected as the MACT floor adequately represents the average83
level of control emissions ac tually achieved by the average of the units in the top 12 percent, considering ordinary operational variability of those units . Both the analysis of the measured emissions from units representative of the top 12 percent, and the variability analysis, are reasonably designed to provide a meaningful estimate of the average performance, or central tendency, of the best controlled 12 percent of units in a given subcategory. A detailed discussion of the MACT floor methodology is presented in the memorandum “ MACT Floor Analysis for the Industrial, Commercial, and Institutional Boilers and Process Heaters National Emission Standards for Hazardous Air Pollutants” in the docket. 1. Determination of MACT fo r the Fuel

- related HAP In developing the proposed MACT f loor for the fuel

- related HAP (PM, HCl, and mercury), a s described earlier, we are using PM as a surrogate for non

- mercury metallic HAP and HCl as a surrogate for the acid gases

. Table 2 of this preamble present s the number of units in each of the five su bcategories, along with the number of units from which we have collected emission data. Table 2 also present s for each subcategory and fuel

related HAP the number of units comprising the best performing units (top 12 percent), the average emission level of the top 1284 percent, and the MACT floor (99 percent U P L of top 12 percent ) which includes the variability across the best performing units and the long term variability across those units

. Table 2. Summary of MACT Floor Results for the Fuel

- Related HAP fo r Existing Subcategories. Subcategory Parameter PM Lb/MMBtu Mercury Lb/MMBtu HCl LB/MMBtu Units designed for Coal firing No. of sources in subcategory

= 5 77 5 7 8 5 77 5 7 8 5 77 5 7 8

No. of sources with data = 3 50 3 66 269 2 85 302 3 18

No. in MACT floor = 42 4 4 3 3 3 5 3 7 3 9 Avg of top 12% 0.00 75 7. 24E

- 03 0.000000 5 2 5.95E

- 07 0.00 42 4. 23E

- 03 99% U P L of top% (test runs) = 0. 0 2 0179 0.00000 16 1.64E

- 06 0.0 06 7.3 8E

- 03 99% U P L with fuel variability of top% 0.0000 03 2 .88E

- 06

Units designed for Biomass firing No. of sources in subcategory

= 420 420 420

No. of sources with data = 1 97 1 9 2 93 9 1 94 9 2

No. in MACT floor = 24 12 1 1 12 Avg of top 12% 0.0 133 6. 06E

- 03 0.00000 02 9 3.46E

- 07 0.00 02 4. 34E

- 03 99% U P L of top% (test runs) = 0. 07 0 162 0.00000 06 7.52E

- 07 0.0 006 6. 00E

- 03 99% U P L with fuel 0.00000 07 8.88E

- 07 Formatted Table85 variability of top% Units designed for Liquid Fuel firing No. of sources in subcategory

= 8 3 1 8 26 8 3 1 8 26 8 3 1 8 26

No. of sources with data = 86 91 1 50 1 77 1 60 1 90

No. in MACT floor = 1 1 18 22 20 2 3 Avg of top 12% 0.001 5 1. 40E

- 03 0.00000 38 1.91E

- 06 0.000 26 2 .59E

- 04 99% U P L of top% (test runs) = 0. 0 035 0 0 3 23 0.000007 2 .78E

- 06 0.00 03 3. 26E

- 04 99% UP L with fuel variability of top% 0.00000 8 3 .97E

- 06

Units designed for NG/RG other gas firing No. of sources in subcategory

= 1 0 , 661 19 9 1 0 , 661 19 9 1 0 , 661 19 9

No. of sources with data = 1 33 1 3 16 8 11 8

No. in MACT floor = 1 6 2 2 Avg of top 12% 0.0 0 42 0.000 0000 006 0. 000 13 99% UP L of top% (test runs)

= 0.0 3 0.000 00 0002 0. 0002

Units designed for other gas firing No. of sources in subcate gory

= 19 6 19 6 19 6

No. of sources with data = 14 8 8

No. in MACT floor = 2 1 1 Avg of top 0.0 11 0.000000 0 0.000 00186

12% 83 8.25E

08 7 1.70E

06 99% U P L of top% (test runs) = 0. 05 0 4 5 0.0000 002 1.86E

- 07 0. 000003 2.50E

- 06 Metal Processing Furnaces No. of sou rces in subcategory

= 749 749 74 9

No. of sources with data = 9 6 8

No. in MACT floor = 2 1 1 Avg of top 12% 0.0 047 0.000 000033 0. 000086 99% U P L of top% (test runs)

= 0.0 2 0.000 0002 0. 0002

For eight three case s, the proposed new and existing sou rce MACT floors are almost identical because the best performing 12 percent of existing unit s (for which we have emissions information) is only one , or two or three sources. The reason we look to the best performing 12 percent of sources , even though we have data on fewer than 5 sources, is that the se sub categor ies consist of 30 or more unit s. CAA s ection 112(d)(3)(A) provides that standards for existing sources shall not be less stringent than “ the average emission limitation achieved by the best perfor ming 12 percent of the existing sources (for which the Administrator has emissions information), * * * in the category or subcategory for categories and87 subcategories with 30 or more sources. ” A plain reading of the above statutory provisions is to apply the 12 percent rule in deriving the MACT floor for those categories or subcategories with 30 or more sources. The parenthetical “ (for which the Administrator has emissions information) ” in CAA section 112(d)(3)(A) modifies the best performing 12 percent o f existing sources, which is the clause it immediately follows. However, in cases where there are 30 or more sources but little emission data , this results in only a few unit s setting the existing source floor with the result that the new and existing source MACT floors are almost identical. In contrast, if th ese sub categor ies had less than 30 sources, we would be required to use the top five best performing sources, rather than the one , two , or three two that comprise the top 12 percent. Section 112 ( d)(3)(B). We are seeking comment on whether, with the facts of this rulemaking, we should consider reading the intent of Congress to allow us to consider five sources rather than just one , two , or three

. two. First, it seems evident that Congress was c oncerned that floor determinations should reflect a minimum quantum of data: At least data from 5 sources for source categories of less than 30 sources (assuming that data from 5 sources exist). Second, it does not appear that this concern would be any l ess88
for sub categories with 30 or more sources. We are specifically requesting comment on interpretive this interpret ation relating to the proposed MACT floors

. 2. Determination of MACT for Organic HAP In developing the MACT floor for organic HAP, as desc ribed earlier, we are using CO as a surrogate for non

- dioxin organic HAP. Table 3 of this preamble present s the number of units in each of the 1 1 subcategories, along with the number of units from which we have collected emission data. Table 3 also

prese nted for each subcategory and CO and D/F the number of units comprising the best performing units (top 12 percent), the average emission level of the top 12 percent, and the MACT floor (99 percent U P L of top 12 percent ) which includes the variability acros s the best performing units and the long term variability. We calculated the MACT floors based on the upper 99 th percentile UPL from the average performance of the best performing units and their variances as described earlier for the fuel

- related HAP

. Table 3. Summary of MACT Floor Results for the Organic HAP Subcategories. Subcategory Parameter CO (ppm @ 3 percent oxygen ) Dioxin/Furan ( Total TEQ) (ng/dscm @ 7 percent89

oxygen ) Stoker

– Coal No. of sources in subcategory = 360 36 1 360 36 1 No. of sou rces with data = 55 61 15 1 4 No. in MACT floor = 7 8 2 Avg of top 12% 19 21.4 0. 0018 0018 2 99% U P L of top% (test runs) = 40 4 8.8 0. 003 00 274 Fluidized Bed

- Coal No. of sources in subcategory = 31 31 No. of sources with data = 14 1 7 11 1 2 No. in MACT flo or = 2 3 2 Avg of top 12% 1 7 1 2.5 0. 0 0047 0 0047 1 99% U P L of top% (test runs) = 40 21.4 0. 002 00 168
PC

– Coal No. of sources in subcategory = 186 186 No. of sources with data = 40 4 1 10 No. in MACT floor = 5 2 Avg of top 12% 14 1 9.2 0. 0 016 0 01 58 99% U P L of top% (test runs) = 70 82.8 0. 003 003 07 Stoker

– Biomass No. of sources in subcategory = 334 320 334 3 20 No. of sources with data = 124 1 19 16 No. in MACT floor = 15 2 Avg of top 12% 260 2 03 0. 0 0082 0 008 1 9 99% U P L of top% (test runs) = 780 551 0. 003 00 3 39 Fluidized Bed

– Biomass No. of sources in subcategory = 26 12 26 12

No. of sources with data = 18 7 7 6 No. in MACT floor = 5 5 Avg of top 12% 92 9 7.1 0. 006 00 507 99% U P L of top 12 % (test runs) = 230 2 45 0. 02 0 127 Suspension No. of sources in 48 62 48 6290 Burner/ Dutch Oven subcategory = No. of sources with data = 7 1 7 3 No. in MACT floor = 1 3 1 Avg of top 12% 69 362 0. 0095 0095 2 99% U P L of top 12 % (test runs) = 220 1010 0. 03 0 279 99% U P L of top 12 % with load variability 460

Fuel Cell

– Biomass No . of sources in subcategory = 26 26 No. of sources with data = 18 1 6 7 No. in MACT floor = 5 5 Avg of top 12% 130 0. 0055 0055 2 99% U P L of top 12 % (test runs) = 270 2 62 0. 02 0 148 Units designed for Liquid fuel firing No. of sources in subcategory = 831 8 26 831 8 26

No. of sources with data = 115 11 6 1 5 1 7 No. in MACT floor = 14 2 3 Avg of top 12% 0. 44 44 3 0. 0 0055 0 00 73 3 99% U P L of top 12 % (test runs) = 1 0.91 1 0. 002 00 182 Units designed for NG/RG other gases firing No. of sources in subcategory = 10,661 19 9 10,661 19 9

No. of sources with data = 723 7 5 8 5 No. in MACT floor = 87 9 1 Avg of top 12% 1.7 0.0 737 0. 0 026 002 6 7 99% U P L of top 12 % (test runs) = 20 0.134 0. 01 008 28 Units designed for other No. of sources in subcategory = 196 19691

gases firing No. o f sources with data = 70 5 No. in MACT floor = 9 1 Avg of top 12% 0.08 0. 0027 99% U P L of top 12 % (test runs) = 1 0.008 Metal Processing Furnaces No. of sources in subcategory = 749 749

No. of sources with data = 14 7 No. in MACT floor = 2 1

Av g of top 12% 0.38 0.0026 99% U P L of top 12 % (test runs) = 2 0.004

For organic HAP, a s previously discussed above for the fuel

- related , we account for variability in setting floors, not only because variability is an element of performance, but becaus e it is reasonable to assess best performance over time. Here, however, we know that the organic HAP emissions will also

vary over the operating range of the unit , unlike fuel

- related HAP emissions . Organic HAP are combustion

- related pollutants. That is , their levels of emissions are a function of the combustion process. Combustion units operate most efficiently when operated at or near their design capacity. The combustion efficiency tends to decrease as the unit’s load ( s team production) decreases. Most industrial or commercial/institutional units do not continuously operate at or92 near their design capacity but operate according to the facility’s demand for steam. Thus, operation at lower capacity rates must be accounted for in determining operation al variability. As part of EPA’s information collection effort, we obtained data on organic HAP (THC and CO) from six units ( two coal

- fired,

two biomass

- fired, and two gas - fired) that were collected by using CEM over a 30

- day period. All of these units were selected to test using CEM to provide variability information because their stack test results indicated that they were among the best performing units. The CEM S data shows that CO (as a surrogate for non - dioxin organic HAP ) from best performing u nits did not vary much , except for one biomass design type, when such unit is operate d at below design capacity. Therefore, even though ICI units, due to steam demand, may operate at these low load conditions for long continuous periods , no additional var iability due to operating load needs to be account ed for , except for boilers in since the biomass suspension burner/Dutch oven subcategory

. average CO emission levels that include these low load conditions are within the variability range determined by the statistical analyses of CO emissions from the best performing units

. Thus, to the MACT floor 99 percent UPL values93
determined from the stack test data for organic HAP CO emissions ,

we have added an are proposing to add no additional variability factor to ac count for load variability only for boilers in the biomass suspension burner/Dutch oven subcategory

. . This approach reasonably ensures that the emission limit selected as the MACT floor adequately represents the average level of control actually achieve d by units in the top 12 percent, considering ordinary operational variability of those units . Both the analysis of the measured emissions from units representative of the top 12 percent, and the variability analysis of those units , are reasonably designe d to provide a meaningful estimate of the average performance, or central tendency, of the best controlled 12 percent of units in a given subcategory. As was the case for the eight three fuel

- dependent MACT floors, the proposed new and existing source MAC T floors for twelve eight combustion

- dependent subcategories are almost identical because the best performing 12 percent of unit s (for which we have emissions information) is only one or two sources. Again, t he reason we look to the best performing 12 perc ent of sources is that the se sub categor ies consist of 30 or more unit s.
In contrast, if th ese sub categor ies had less than 30 sources, we would be required to use the top five best performing sources,94
rather than the one or two that comprise the top 12 per cent. As stated previously, w e are seeking comment on whether, with the facts of this rulemaking, we should consider reading the intent of Congress to allow us to consider five sources rather than just one, two , or three

. We are specifically requesting c omment

on this interpret ation relating to the proposed MACT floors

. 3. Determination of the Work Practice Standard CAA section 112(h)(1) states that the Administrator may prescribe a work practice standard or other requirements, consistent with the provi sions of CAA sections 112(d) or (f), in those cases where, in the judgment of the Administrator, it is not feasible to enforce an emission standard. CAA s ection 112(h)(2)(B) further defines the term “not feasible” in this context to apply when “the applic ation of measurement technology to a particular class of sources is not practicable due to technological and economic limitations.” The standard reference methods for measuring emissions of

mercury, CO (as a surrogate for organic HAP), D/F, HCl (as a

s urrogate for acid gases) and PM (as a surrogate for non

- mercury metals) are EPA Methods 29, 10 , 23, 26A and 5. These methods are reliable but relatively expensive as a group. However, the methods are generally not able to accurately sampl e small diameter (less than 12 inches) stacks. For example, in these95 small diameter stacks, the conventional EPA Method 5 stack assembly blocks a significant portion of the cross

- section of the duct and , if unaccounted for, could cause inaccurate measurements. Many exis ting small boilers and process heaters have stacks with diameters less than 12 inches. The stack diameter is generally related to the size of the unit. Units that have capacity below 10 million Btu per hour generally have stacks with diameters less than 12 inches. Also, many existing small unit s do not currently have sampling ports or a platform for accessing the exhaust stack which would require an expensive modification to install sampling ports and a platform. We conducted a cost analysis 4

4 Memorandum: Methodology for Estimating Impacts from Industrial, Commercial, and Institutional Boilers and Process Heaters at Major Sources of Hazardous Air Pollutant Emissions, March 23, 2010. to evaluat e the economic impact of the testing and monitoring costs that facilities with small units would incur to demonstrate compliance with the proposed emission limits. The annual compliance costs imposed on each facility is for the costs of the stack test s . The compliance costs imposed on each facility would not only include the costs of the stack test s and monitoring equipment but would also include the capital costs of any installed control equipment. We estimate that the total capital costs of installing control equipment on the over 7,400 small boilers and96 process heaters to achieve the proposed emission limits would be $ 6.3 billion . In addition to these costs, since many of these small units do not have test ports or testing platforms installed in order to conduct performance testing. Prior to conducting a stack test each unit would need to construct or rent scaffolding and install test ports. EPA estimates that these small sources would incur an additional $185 million to install test ports and rent te mporary scaffolding. Many establishments in each industry, commercial, or institutional sector are associated with multiple (as many as a 100 700 ) small units. The results of the analysis indicate that the annual costs for testing and monitoring costs alo ne would have a significant adverse economic impact on these facilities. The severity of the economic impact would depend on the size of the facility. Based on this analysis, the Administr ator has determined , as allowed under CAA section 112(h ), ) that it is not feasible to enforce emission standards for a particular class of existing boilers and process heaters because of the technological and economic l imitations described above. Thus, a work practice, as discussed below, is being proposed to limit th e emission of HAP for existing boilers and process heaters having a heat input capacity of less than 10 million Btu per hour

. We are97 specifically requesting comment on whether a threshold higher than 10 million Btu per hour meets the technical and economi c limitations as specified in CAA section 112(h). For existing units , the only work practice being used that potentially controls HAP emissions is a tune

- up. Fuel dependent HAP are typically controlled by removing them from the flue gas after combustion . The only work practices expected to minimize fuel dependent HAP emissions are reducing the fuel usage or fuel switching to a fuel type with a lower HAP content or reducing the fuel usage. As discussed later , we determined that fuel switching is not an appropriate emission reduction approach. However, f uel

. F uel usage can be reduced by improving the combustion efficiency of the unit

. , such as, by a tune

- up . As combustion efficiency decreases, fuel usage increases to maintain energy output resulting in increased emissions. On the other hand, organic HAP are formed from incomplete combustion of the fuel. The objective of good combustion is to release all the energy in the fuel while minimizing losses from combustion imperfections and excess air. The combination of the fuel with the oxygen requires temperature (high enough to ignite the fuel constituents), mixing or turbulence (to provide intimate oxygen

- fuel contact), and sufficient time (to complete the process), sometimes referred to the three T s of combustion.98 Good combustion practice (GCP), in terms of combustion units , could be defined as the system design and work practices expected to minimize organic HAP emissions. We have obtained information on unit s reported using GCP, as part of the in formation collection effort for the NESHAP. The data that we have suggests that unit s typically conduct

tune

- ups. We also reviewed s tate regulations and permits. The work practices listed in s tate regulations includes tune

- ups (10

s tates), operator trai ning (1 s tate), periodic inspections (2 States), and operation in accordance with manufacturer specifications (1 State). Of the unit s with a capacity of less than 10 MMBtu/h that responded to EPA’s information collection effort for the NESHAP, 80 percent reported conducting a tune

- up program. Ultimately, we determine that at least 6 percent of the unit s in each of the subcategory are subject to an annual a
tune

- up requirement under other applicable requirements

. Therefore, the proposed work practice of an annual a tune

- up 5

We are also proposing a work practice stand ard under section 112(h) that would require an annual tune

- up for existing program does establish the MACT floor for HAP emissions from existing unit s with a heat input capacity of less than 10 MMBtu/h.

5 Tune

- up procedure is specified in section 6 3.7540 of this proposed rule and includes making adjustments to the burner to optimize the flame to minimize CO emissions consistent with the manufacturer’s specifications.99 boilers and process heaters combusting natural gas or refinery gas. These boilers and process heaters are units include d in the Gas 1 and metal process ing furnace subcategories. We are specifically seeking comment on whether the application of

m easurement methodology to sources in this subcategory is impracticable due to technological or economic limitations, as specified in section 112(h)(2)(B). This proposal is based on several reasons. First, the capital costs estimated for installing contro ls on these boilers and process heaters to comply with MACT limits for the five HAP groups is over $14 billion to install a combination system of a fabric filter (for PM, mercury, and D/F control) and a wet scrubber (for HCl control). This is higher than the estimated combined capital cost for boilers and process heaters in the other subcategories to comply with the proposed emission limits

. Th e projected control system needed for boilers and process heaters in the other subcategories is also a combined f abric filter/wet scrubber system

. Second, we believe that proposing emission standards for

gas - fired boilers and process heaters that result in the need to employ the same emission control system as needed for the other fuel types would have the negative benefit of providing a disincentive for switching to gas as a control technique (and a100 pollution prevention technique) for boilers and process heaters in the other fuel subcategories . In addition, emission limits

on gas - fired boilers and process heaters m ay have the negative benefit of providing an incentive for a facility to switch from gas (considered a “clean” fuel) to a “dirtier” but cheaper fuel (i.e., coal). It would be inconsistent with the emissions reductions goals of the CAA, and of section 112 in particular, to adopt requirements that would result in an overall increase in HAP emissions. We are soliciting comment on the extent to which natural gas facilities would be expected to switch to a “dirtier” fuel if emissions limits for such facilities are adopted. Thus, a work practice, as discussed above for small boilers and process heaters, is being proposed to limit the emission of HAP for existing natural gas

- fired and refinery gas

- fired boilers and process heaters. We request comments on whether the emission limits listed in Tables 2 and 3 Table 4 of this preamble for the Gas 1 and Metal processing furnace P rocess F urnace subcategories should be promulgated. Comments should include detailed information regarding why emission limits for these gas

- fi red boilers and process heaters are appropriate.101
Table 4 . Summary of MACT Floor Results for the Gas 1 and Metal
Process Furnace Subcategories.

Subcate gory Parame ter PM Lb/MMB tu Mercury Lb/MMBt u HCl LB/MMB tu CO (ppm @ 3 percent oxygen) Dioxin/Furan (Total TEQ) (ng/dscm @ 7 percent oxygen) Units designe d for NG/RG firing No. of source s in subcat egory

= 10, 783 10, 783 10, 783 10, 783 10, 783

No. of source s with data = 1 44 1 4 11 7 54 8

No. in MACT floor

= 18 2 2 91 1

Avg of top 12% 0.00 38 8 1.1E

- 0 7 1 .01E

04 1. 45 0.0 026

99% UPL of top% (test runs)

= 0.03 2.0E

- 07 0.0002 20 0. 01

Metal Process ing Furnace s No. of source s in subcat egory

= 749 749 749 749 749

No. of source s with data = 9 7 9 1 5 7

No. in MACT floor 2 1 2 2 1102

E. How did EPA consider beyond

- the

- floor options for existing units ? Once the MACT floor determinations were done for each subcategory, we considered various regulatory op tions more stringent than the MACT floor level of control (i.e., technologies or other work practices that could result in lower emissions) for the different subcategories. A detailed description of the beyond

- the

- floor consideration is in the memorandum “Methodology for Estimating Cost and Emissions Impacts for Industrial, Commercial, Institutional Boilers and Process Heaters National Emission Standards for Hazardous Air Pollutants” in the docket.

W e could not identif y better control technolog ies HAP emis sions reduction approaches that could achieve greater emissions reductions of HAP t han the control technology combination ( fabric filter , carbon injection, scrubber , and GCP ) = Avg of top 12% 0.0047 3.3E

- 08 0.000 1 92 0.38 0.0026

99% UPL of top% (test runs)

= 0.02 2.0E

- 07 0.000 4 2 0.004103
that we expect will be used to meet the MACT floor level of control. For each s ubcategory, fuel switching to natural gas is a regulatory a n option more stringent than the MACT floor that would reduce HAP emissions. We determined that fuel switching was not an appropriate beyond

- the

- floor option. F irst , natural gas supplies are not a vailable in some areas, and supplies to industrial customers can be limited during periods when natural gas demand exceeds supply. Additionally, the estimated emissions reductions that would be achieved if solid and liquid fuel units switched to natural g as were compared with the estimated cost of converting existing solid fuel and liquid fuel units to fire natural gas. The annualized cost of fuel switching was estimated to be $ 1 3. 5 billion compared with $ 3. 5 .1 billion under the floor approach. The emiss ion reduction associated with fuel switching was estimated to be 5,114 4 , 303 tons per year for metallic HAP, 19 8 tons per year for mercury, and 40,089 34783 tons per year for inorganic HAP (HCl and HF). The cost for fuel switching is over double the cost of the floor approach while the emission reductions associated with fuel switching are approximately the same. Additional detail on the calculation procedures is provided in the memorandum “Development (2010) of Fuel Switching Costs and Emissions104
Reductions for Industrial, Commercial, and Institutional Boilers and Process Heaters National Emission Standards for Hazardous Air Pollutants” in the docket. We also considered the pollution prevention and energy conservation measure of an energy assessment/ audit a s a beyond

the

- floor option for HAP emissions. A n energy a ssessment provides valuable information on improving energy efficiency. An energy assessment, or audit, is an in

- depth energy study identifying all energy conservation measures appropriate for a f acility given its operating parameters. An energy a ssessment refers to a process which involves a thorough examination of potential savings from energy efficiency improvements, pollution prevention, and productivity improvement. Besides reducing operatin g and maintenance costs, improving energy efficiency reduces negative impacts on the environment and results in reduced emissions and improved public health . I mprovement in energy efficiency results in decrease d fuel use which results in a corresponding d ecrease in emissions (both HAP and non

- HAP) from the combustion unit , but not necessarily all those present. a decrease in emissions of all HAP emitted

. The Department of Energy has conducted energy a ssessment s at selected manufacturing facilities and repo rts that facilities can reduce fuel/energy use by 10 to 15 percent by using best105 practices to increase their energy efficiency. Many best practices are considered pollution prevention because they reduce the amount of fuel combusted which results in a

cor responding reduction in emissions from the fuel combustion. The most common best practice is simply tuning the boiler to the manufacturer’s specification. The one

- time cost of an energy assessment ranges from $2500

to $55,000 depending on the size of th e facility. The total annualized cost if each major source facility conducted an energy assessment is estimated at $26 million. If a facility elected to implement implement ed the cost

- effective energy conservation measures identified in the energy audit a s sessment , it would potentially result in greater HAP reduction than achieved by a boiler tune

- up alone

. and potentially reducing HAP emissions (HCl, HF, Hg, VOC, and dioxin/furan) by an additional 2, 3 00 to 4 , 5 00 tons per year. In addition, the costs of an y energy conservation improvement will be offset by the cost savings in lower fuel costs. Therefore, we decided to go beyond the MACT floor for th is proposed rule for the existing unit s. Th ese proposed standards for existing unit s include the requirement of a performance of an energy a ssessment to identify

cost

- effective e nergy conservation measures

. Since there was insufficient information to determine if requiring106 implementation of cost

- effective measures were economically feasible, we are seeking comm ent on this point. In th is proposed rule, we are defining a c ost

- effective energy conservation measure to be any measure that has a payback (return of investment) period of 3 years or less. This payback period was selected based on section 325(o)(2)(B)( iii) of the Energy Policy and Conservation Act which states that there is a presumption that an energy conservation standard is economically justified if the increased installed cost for a measure is less than three times the value of the first

- year energy savings resulting from the measure. We believe that an energy assessment is an appropriate beyond

- the

- floor control technology because it is one of the measures identified in CAA section 112(d)(2)

. CAA s ection 112( d)(2) states that “Emission standards p romulgated ... and applicable to new or existing sources ... is achievable ... through application of measures, processes, methods, systems or techniques including, but not limited to measures which

– (A) reduce the volume of, or eliminate emissions of, such

p ollutants through process changes, substitution of materials or other m o di fi cations, The purpose of an energy assessment is to identify energy conservation measures (such as, process changes or other107 modifications to the facility) that can be implemented t o reduce the facility energy demand which would result in reduced fuel use. Reduced fuel use will result in a corresponding reduction in HAP, and non

- HAP, emissions. Thus, an energy assessment, in combination with the MACT emission limits will result in the maximum degree of reduction in emissions as required by 112(d)(2). Therefore, we are proposing to require all existing sources to conduct a one

- time energy assessment to identify

cost

- effective energy conservation measures. In addition to the energ y assessment requirement, we are proposing an We are specifically requesting comment on: (1) whether our estimates of the assessment costs are correct; (2) is there adequate access to certified third party assessors; (3) are online tools adequate to inform the facility’s decision to make efficiency upgrades; (4) is the definition of “cost

effective” appropriate in this context since it refers to payback of energy saving investments without regard to the impact on HAP reduction; and (5) what rate of return s hould be used.

W e considered proposing a beyond

- the

- floor requirement for certain sources in the natural gas and refinery gas subcategory (i.e., the Gas 1 subcategory). Specifically, we are considered proposing that facilities with boilers or process heat ers108 combusting refinery gas install and maintain a carbon adsorber bed system 6

6 Carbon adsorption of mercury can be accomplished by (a) injecting dry carbon wit h or without other dry sorbents into the offgas upstream of a PM control device (typically a baghouse), or (b) using a fixed or moving bed of granular carbon through which the offgas flows. In a typical fixed bed carbon adsorption system, the flue gas flo ws through a vessel packed with a specified depth of the carbon granules. The bed and packing are designed to limit the linear velocity of the offgas in the bed to increase the contact time with the carbon. Due to the increased contact times and typically lower operating temperatures, better removal efficiencies can be achieved than for carbon injection. At a to remove mercury from the refinery gas before combustion in a boiler or process heater. Based on data from the information collection effort, refinery gas contains high levels of mercury compared to natural gas, and significant and additional mercury reductions can be achieved from units combusting refinery gas. In addition, the cost of Consequently, we analyzed the mercury controls for such units is reasonable, because the e missions reductions and additional cost of adopting this work practice. T he annualized cost of the carbon adsorber bed system to treat the refinery gas prior to combustion is less expensive than installing estimated to be about 1.6 billion dollars with a f abric filter/carbon injection system on each individual unit to treat its exhaust gas , compared to the significant mercury emissions reductions emission reduction of 0.8 tons. The results indicated that would be achieved. EPA is while additional mercury e missions reductions would be realized, the costs would be too high to

residence time of 10 seconds in the carbon bed, virtually all of the mercury can be removed. (Ref. NUCON INTERNATIONAL, Inc., “ Design & Performance Characteristics of MERSORBB Mercury Adsorbents in Liquids and Gases,” NUCON 11B28, August 1995.)109 consider it a feasible beyond

- the

- floor option. Nonair quality health, environmental impacts, and energy effects were not significant factors, because there would be little difference i n the nonair quality health and environmental impacts of requiring the installation of carbon bed adsorbers. Therefore, we are not proposing installation of a carbon adsorber bed system as a beyond

- the

- floor requirement for natural gas boilers and process heaters because such a requirement would achieve minimal emissions reductions from such units, and therefore the cost of installing and maintaining the system is not warranted

. F. Should EPA consider different subcategories for solid fuel boilers and process heaters? The boilers and process heaters source category is tremendously heterogeneous. EPA has attempted to identify subcategories that provide the most reasonable basis for grouping and estimating the performance of generally similar units usin g the available data. We believe that the subcategories we selected are appropriate. EPA requests comments on whether additional or different subcategories should be considered. Comments should include detailed information regarding why a new or differe nt subcategory is appropriate (based on the available data or adequate data submitted with the comment), how EPA should define110 any additional/different subcategories, how EPA should account for varied or changing fuel mixtures, and how EPA should use the

a vailable data to determine the MACT floor for any new or different categories.
G. How did EPA determine the proposed emission limitations for new units ? All standards established pursuant to section 112 of the CAA must reflect MACT, the maximum degree of reduction in emissions of air pollutants that the Administrator, taking into consideration the cost of achieving such emissions reductions, and any nonair quality health and environmental impacts and energy requirements, determines is achievable for each category. The CAA specifies that MACT for new boilers and process heaters shall not be less stringent than the emission control that is achieved in practice by the best

- controlled similar source

. T his minimum level of stringency is the MACT floor for new units. However, EPA may not consider costs or other impacts in determining the MACT floor. EPA must consider cost, nonair quality health and environmental impacts, and energy requirements in connection with any standards that are more stringent than the MACT floor (beyond

- the

- floor controls).

H. How did EPA determine the MACT floor for new units ?111 Similar to the MACT floor p rocess used for existing units, the approach for determining the MACT floor must be based on available emissions test data. Using such an approach, we calculated the MACT floor for a sub category of sources by ranking the emission test results from units within the sub category from lowest to highest to identif y the best controlled similar source . The MACT floor limits for each of th e HAP and HAP surrogates ( PM, mercury, CO , HCl, and D/F ) are calculated based on the performance ( numerical average) of the lowest emitting (best controlled) source for each pollutant in each of the subcategories. The MACT floor limit s for new sources wer e calculated using the same formula as was used for existing sources. However, as was the case for the existing MACT floor analysis , we determined that it was inappropriate to use only this MACT floor approach to determine variability and to establish emi ssion limits for

new boilers and process heaters. The main problem with using only the HAP emissions test data is that the data may not reflect the variability of fuel

- related HAP from the best controlled similar source over the long term. Based on our

c urrent information, fuel

- related HAP levels in the various fuels can vary significantly over time

. The variations in fuel

-112
related HAP inputs directly translate to a variability of fuel

related HAP stack emissions. As previously discussed above, we accoun t for variability of the best

- controlled source in setting floors, not only because variability is an element of performance, but because it is reasonable to assess best performance over time. If we do not account for this variability, we would expect tha t even the best controlled similar source would potentially exceed the floor emission levels a significant part of the time which would

mean that their variability was not properly accounted for when setting the floor

. We c alculated the MACT floor based o n the

UPL (upper 99th percentile) as described earlier from the average performance of the best controlled similar source , Students t

- factor, and the total variability of the best

controlled source

. This approach reasonably ensures that the emission limit selected as the MACT floor adequately represents the average level of control actually achieved by the best controlled similar source , considering ordinary op erational variability. A detailed discussion of the MACT floor methodology is presented in the m emorandum “MACT Floor Analysis for the Industrial, Commercial, and Institutional Boilers and Process113
Heaters National Emission Standards for Hazardous Air Pollutants” in the docket. The approach that we use to calculate the MACT floors for new sources is somewhat different from the approach that we use

to calculate the MACT floors for existing sources. While the MACT floors for existing units are intended to reflect the

average performance achieved by the average of the best performing twelve percent of s ources, the MACT floors for new units are meant to reflect the emission control that is achieved in practice by the best controlled source. Thus, for existing units, we are concerned about estimating the central tendency of a set of multiple units, while for new u nits, we are concerned about estimating the level of control that is representative of that achieved by a single best controlled source. As with the analysis for existing sources , the new unit analysis must account for variability. To accomplish this for new sources, for the fuel dependent HAP emissions, we determine d what the best controlled source can achieve has achieve d in light of the inherent and unavoidable variations in the HAP content of the fuel that such unit might potentially use. For non - fuel dependent HAP emissions, on the other hand, we look at the inherent variability of the control technology used by the best

controlled source in the sub category. These approaches,114 respectively, represent the most reasonable way to estimate perfor mance for purposes of establishing MACT floors for new units, given the data available. For fuel dependent HAP emissions (mercury and HCl), we calculated the variability factor by looking at data on HAP variability in fuel obtained through our informat ion collection request. We derived the fuel dependent variability factor by dividing the highest observed HAP concentration by the lowest observed HAP concentration from the fuel analys e s from the best

controlled source . Once we calculated the fuel depen dent variability factors, we applied these factors to the average measured emissions performance of the unit with the best data controlled similar source to derive the MACT floor level of control. This approach reasonably estimates the best source’s level of control emissions , adjusted for unavoidable variation in fuel characteristics which have a direct impact on emissions. 1. Determination of MACT for the Fuel

- related HAP In developing the MACT floor for the fuel

- related HAP (PM, HCl, and mercury), as d escribed earlier, we are using PM as a surrogate for non

- mercury metallic HAP and HCl as a surrogate for the acid gases. Table 4 5 present s for each subcategory and fuel

- related HAP the average emission level of the best controlled similar source and the M ACT floor (99 percent U P L)115 which includes the variability across the best controlled similar source and the long term variability of that source

. Table 4

. 5

. Summary of MACT Floor Results for the Fuel

- Related

HAP for New Sources

. Subcategory Parameter PM Lb/MMBtu Mercury Lb/MMBtu HCl LB L b /MMB tu Units designed for Coal firing Avg of top performer 0. 0004 00 0 396 0.0000001 1.18E

- 07 0.0000 1 5 3.85E

- 05

99% U P L of top (test runs) = 0. 00 09 00 09 28 0.00000 04 3.89E

- 07 0.0 0 00 4 5 .21E

- 05 Units designed for Biomass firing Avg of top performer 0. 0 022 0 0 2 16 0.0000001 9.73E

- 08 0.000 79 7 .85E

- 04

99% U P L of top (test runs) = 0. 007 007 11 0.000000 4 1.86E

- 07 0.00 3 3.0 7E

- 03 Units designed for Liquid Fuel firing Avg of top performer 0. 0 006 0 0 0 511 0.0000000 07 5.87E

08 0.0001 3. 99E

- 04

99% U P L of top (test runs) = 0. 0 02 0 0 1 54 0.0000000 3 2.47E

- 07 0.000 2 9. 80E

- 04 Units designed for NG/RG other gas firing Avg of top performer 0. 00 65 00 0 42 0.0000000 003 8.25E

08 0.0000 37 1.70E

- 06

99% U P L of top (test runs) = 0. 0 24 00 2 4 0.0000000 02 1.86E

07 0.0000 6 2 .5 0E

- 06 Units designed for other gas firing Avg of top performer 0.0 002 0.00 000005 0.0 0000 17

99% U P L of top (test 0.0 01 0.00 00000 6 0.0 0000 25116 runs) = Metal Processing Furnaces Avg of top performer 0.0 065 0.00 0000033 0.0 00037 99% U P L of top (test runs) = 0.0 2 0.00 00002 0.0 0006

2. Determination of MACT for Organic HAP In developing the MACT floor for organic HAP, as described earlier, we are using CO as a surrogate for non

- dioxin organic HAP. Table 5 6 present s for each subcategory and CO and D/F the average emission level of the best controlled similar source and the MACT floor (99 percent U P L) which includes the variability across the best controlled similar source and the long term variability of that source

. Table 5

. 6

. Summary of MACT Floor Resul ts for the Organic HAP for New Sources

. Subcategory Parameter CO (ppm @ 3 percent oxygen ) Dioxin/Furan ( TEQ ) (ng/dscm @ 7 percent oxygen ) Stoker

– Coal Avg of top performer 0.2 62 4.29 0. 00253 00 152 99% U P L of top% (test runs) = 1 6.53 0. 00 6 00 282 Fluidiz ed Bed

- Coal Avg of top performer 0.231 8.26 0.00191 9.05E

- 06 99% U P L of top% (test runs) = 0 39

. 9 * 0.003 2.54E

05 PC

– Coal Avg of top performer 25. 0 .279 0.0 182 1.04E

03 99% U P L of top% (test runs) = 0 97 .5 * 0.05 1.47E

- 03117
Stoker

– Biomass Avg of top perf ormer 3.74 920 0.019 2 1.52E

05 99% U P L of top% (test runs) = 1 2 3730 * 0.0 2 4.86E

- 05 Fluidized Bed

– Biomass Avg of top performer 0.0 467 25.8 0. 183 2.27E

03 99% U P L of top% (test runs) = 0. 9 34.2 1. 6 .48E

- 03 Suspension Burner/ Dutch Oven Avg of top performer 1.22 352 2.49 9.52E

- 03

99% U P L of top% (test runs) = 4 3 1050* 2. 5 79E

- 02 Fuel Cell

– Biomass Avg of top performer 2.37 110 0.0179 2.42E

04 99% U P L of top% (test runs) = 4 264* 0. 1 4.17E

- 04 Units designed for Liquid fuel firing Avg of top performer 0. 12 9 12 5 0 .00 177 1.09E

- 03

99% U P L of top% (test runs) = 0. 1 3 1 25 0.00 4 1.52E

03 Units designed for NG/RG other gases firing Avg of top performer 0. 0129 0. 0127 2.67E

03

99% U P L of top% (test runs) = 0. 01 3 0129 0. 01 8.28E

- 03 Units designed for other gases firing Avg of top performer 0.168 0.045

99% U P L of top% (test runs) = 6 0. 2 Metal Processing Furnaces Avg of top performer 1.1 0.0425

99% U P L of top% (test runs) = 35 0.2118 *Value is higher than existing floor limit in the same subcategory. Therefore defaulted to existing floor limit for the same subcategory.

For organic HAP, a s previously discussed above for the fuel

- related , we account for variability in setting floors, not only because variability is an element of performance, but because it is reasonable to a ssess best performance over time. Here, we know that CO (as a surrogate for non - dioxin organic

HAP ) emissions does not vary significantly over the operating range of the unit. Thus, we have not added any additional operational variability to account for operation at lower capacity rates. We are proposing a work practice standard under section 112(h) that would require an annual tune

- up for new boilers and process heaters combusting natural gas or refinery gas. These boilers and process heaters are uni ts included in the Gas 1 and metal processing furnace subcategories. We are specifically seeking comment on whether the application of measurement methodology to sources in this subcategory is impracticable due to technological or economic limitations, as specified in section 112(h)(2)(B). This proposal for new boilers and process heaters combusting natural gas or refinery gas is based on the same reasons discussed previously for existing boilers and process119 heaters combusting natural gas or refinery gas. That is, we believe that proposing emission standards for new gas

- fired boilers and process heaters that result in the need to employ the same emission control system as needed for the other fuel types would have the negative benefit of providing a disin centive for switching to gas as a control technique (and a pollution prevention technique) for boilers and process heaters in the other fuel subcategories. In addition, emission limits

on gas - fired boilers and process heaters may have the negative benefit of providing an incentive for a facility to switch from gas (considered a “clean” fuel) to a “dirtier” but cheaper fuel (i.e., coal). It would be inconsistent with the emissions reductions goals of the CAA, and of section 112 in particular, to adopt requ irements that would result in an overall increase in HAP emissions. We are soliciting comment on the extent to which new facilities would be expected to switch away from natural gas to a “dirtier” fuel if emissions limits for new such facilities are adopt ed. Thus, a work practice, as discussed above for existing boilers and process heaters combusting natural gas or refinery gas, is being proposed to limit the emission of HAP for new natural gas

- fired and refinery gas

- fired boilers and process heaters.120

We r equest comments on whether the emission limits listed in Table 7 of this preamble for new units in the Gas 1 and Metal Process Furnace subcategories should be promulgated. Comments should include detailed information regarding why emission limits for thes e gas - fired boilers and process heaters are appropriate.

Table 7 . Summary of MACT Floor Results for New Units in the Gas 1 and Metal Process Furnace Subcategories.

Subcate gory Parame ter PM Lb/MMB tu Mercury Lb/MMBt u HCl LB/MMB tu CO (ppm @ 3 percent oxygen ) Dioxin/Furan (Total TEQ) (ng/dscm @ 7 percent oxygen) Units designe d for NG/RG firing Avg of top perfor mer 0.0001 3 9.4E

- 08 7.3E

05 0.013 0.0026

99% U P L of top (test runs)

= 0.0005 2 .0E

- 07 0.0002 20 0.01

Metal Process Furnace s Avg of top perfor mer 0 .0065 3

. 3 E

- 08 8.6E

05 0.5 0.0026

99% U P L of top (test runs)

= 0.02 2 .0E

- 07 0.0002 2 0.004121

I. How did EPA consider beyond

- the

- floor for new units ? The MACT floor level of control for new units is based on the emission control that is achieved in prac tice by the best controlled similar source within each of the subcategories. No technologies were identified that would achieve HAP reduction greater than the new source floors for the subcategories. Fuel switching to natural gas is a potential regulat ory option beyond the new source floor level of control that would reduce HAP emissions from non

- gas - fired units . However, based on current trends within the industry, EPA projects that the majority of new boilers and process heaters will be built to fire natural gas as opposed to solid and liquid fuels such that the overall emissions reductions associated with this option would be minimal

. In addition , natural gas supplies are not available in some areas, and supplies to industrial customers can be limit ed during periods when natural gas demand exceeds supply. Thus, this potential control option may be unavailable to many sources in practice. Limited emissions reductions in combination with the high cost of fuel switching and considerations about the av ailability and technical feasibility of fuel switching makes this an unreasonable regulatory option122
that was not considered further

. . 7

An energy assessment is a beyond

- the

- floor standard being proposed for existing facilities. However, we are not proposing it as a beyond

- the

- floor option for new major source facilities since we believe it wou ld not be cost effective because most projected new boilers or process heaters will be installed at existing major source facility which would have already conducted a energy assessment as required by this proposed rule

. We also believe that any new green field major source facility having boilers or process heaters will be designed to operate with energy efficiency

. Nonair quality health, environmental impacts, and energy effects were not significant factors. No beyond

- the

- floor opti ons for gas

- fired boilers were identified.

Based on the analysis discussed above, EPA decided to not go beyond the MACT floor level of control for new sources for
MACT in th is propo sed rule. A detailed description of the beyond

- the

- floor consideration is in the memorandum “Methodology for Estimating Cost and Emissions Impacts for Industrial, Commercial, Institutional Boilers and Process Heaters National Emission Standards for Hazard ous Air Pollutants” in the docket.

J
. What o ther compliance a lternatives were considered?

7 Memorandum “Development (2010) of Fuel Switching Costs and Emission Reductions for Industrial, Commercial, and Institutional Boilers and Process Heaters Nati onal Emission Standards for Hazardous Air Pollutants,” April 2010.123

CAA s ection 112(d)(4) allows the Administrator to set a health

- based standard for a limited set of HAP: “ pollutants for which a health threshold has been establish ed. ” EPA may consider that threshold, with an ample margin of safety, in establishing standards under CAA section 112(d). In the 200 7 rule, EPA took the position that HCl and manganese w ere both

“ health threshold pollutant s” and relied on section 112(d)( 4) in decid i ng to establish alternative standard s for HCl and

manganese . 69 FR at 55239

– 44

. In today’s proposed action, we considered whether to propose the health

- based compliance alternatives that were part of the vacated Boiler MACT standard.

As not ed in the p roposal of the MACT II chemical recovery combustion s ources ( 63 FR 18755 ; April 15, 1998) , “ use of section 112(d)(4) authority is wholly discretionary

. . . [C]ases may arise in which . . . considerations dictate that the Agency should not invoke this authority to establish less stringent standards, despite the existence of a health effects threshold that is not jeopardized.” We further stated in that rule that “in considering appropriate uses of its discretionary authority under section 112(d)(4 ), EPA intends to consider other factors in addition to health thresholds, including uncertainty and potential’ adverse environmental effects,’ as that phrase is defined in section 1 12(a)(7).”124
Thus while we have discretion to set a health

- based standard u nder section 112(d)(4) where we believe a pollutant has an established health threshold, that discretion must be exercised reasonably. As explained further below, we do not believe that establishing a threshold level would provide an “ample margin of safe ty,” as required by section 112(d)(4), and therefore are not proposing to relax the stringency of the emission standard for HCl using the section 112(d)(4) in this

case . We are not proposing health

- based compliance alternatives here for three primary rea sons. First, while the CAA allows the Administrator to consider a health

- based standard, such a standard must be robust enough to allow her to ensure that an ample margin of safety has been provided. Second, since HC l is used as a surrogate for other HAP acid gases hydrogen fluoride and hydrogen cyanide, she must consider whether such a strategy would necessitate setting additional MACT standards for these

gases for which HC l was being used as a surrogate . And third, since the decision to propose health

- based standards is discretionary , consideration can and should be given to all the direct effects that result from controlling HC l emissions. First, t h e classification of HCl as a threshold pollutant is based on only one animal study, and no human data are125
available for review ( 63 FR 18755)

– clearly not sufficient to

ensure protection with adequate margin o f safety

. Second, it is clear that hydrogen chloride (HCl) is a respiratory toxic pollut ant; that is, it can cause irritation in the nose, throat, and upper respiratory tract which could ultimately lead to chronic damage. This is also true of the HAPs hydrogen fluoride (HF) and hydrogen cyanide (HCN), the other acid gas HAPs that may be emitted by coal

- fired boilers which can be controlled via the same technologies, and for which EPA must issue standards in this rulemaking. The respiratory toxicity of HCl is generally considered not to occur at chronic exposure concentrations below the reference concentration, or RfC, which is 20 ug/m3. However, the de termination of this reference concentration does not consider the potential for simultaneous exposures to other respiratory toxicants

. In addition, HCl is corrosive to the eyes, skin, and mucous membranes. Acute inhalation exposure may

cause eye, nose, a nd respiratory tract irritation and inflammation and pulmonary edema in humans. Chronic occupational exposure to hydrochloric acid has been reported to cause gastritis, bronchitis, and dermatitis in workers. Prolonged exposure to low concentrations may a lso cause dental discoloration and erosion. No information is available on the reproductive or developmental effects of hydrochloric acid in126 humans. In rats exposed to hydrochloric acid by inhalation, altered estrus cycles have been reported in females a nd increased fetal mortality and decreased fetal weight have been reported in offspring. EPA has not classified hydrochloric acid for carcinogenicity. The inhalation of HCl has also been known to lead to chemical

- induced asthma in some cases. As such, i ts effects can be manifested when it is inhaled in combination with other asthma

- inducing pollutants (e.g., ozone, formaldehyde, or acrolein), triggering asthma attacks, even at concentration levels well below its RfC. S ince boilers are often located at i ndustrial sites where other pollutants are emitted , it would be reasonable to consider the boiler emissions in conjunction with other emissions at the same site, particularly since such sites are often found in polluted urban areas as well as in polluted

u rban areas

. At a minimum , it would be reasonable to consider the combination of all respiratory toxicants and asthma

exacerbating pollutants in the ambient air near boilers when estimating their potential impacts to the human respiratory system, and when considering the adoption of HCl emission standards less stringent than the MACT approach would dictate , in light of the fact that there can be significant pollutant emissions from other emissions points at industrial sites where boilers are located

. Since EPA cannot quantify with sufficient127 certainty the potential health effects of this complex mixture of pollutants at every industrial site in the country at which a boiler is located, we are choosing to err on the side of protecting public health by not p roposing to use the discretion offered by section 112(d)(4). We further note that there are other adverse environmental effects of HCl emissions from boilers. W hen HCl gas encounters water in the atmosphere, it forms hydrochloric acid, which can contrib ute to further aquatic and terrestrial acidification, ecological impacts that are already causing environmental degradation in many areas of the country. Similarly, when HF gas encounters water in the atmosphere, it forms hydrofluoric acid. We believe th at it is reasonable for EPA to decide not to use its disc retion under section 112(d)(4) to weaken the emission standard for HCl (and in turn for HF) from boilers, adding to this environmental burden, when it is simultaneously investigating ways to reduce e nvironmental degradation from acidification (i.e., EPA is currently considering the adoption of tighter ambient standards for oxides of sulfur (SOx) and oxides of nitrogen (NOx) to reduce environmental acidification). Lastly, setting MACT standards for HC l (as a surrogate for the other HAP acid gases hydrogen fluoride and hydrogen cyanide) and PM (as a surrogate for metals including manganese) is128 anticipated to result in significant control for other pollutants emitted, most notably SO 2 and other non

- HAP a cid gases (e.g., hydrogen bromide), along with condensable PM and will likely provide additional control for mercury and other HAP metals (e.g., selenium). T he additional reductions of SO 2 alone attributable to the proposed MACT standard for HCl are estim ated to be 400,000 tons per year in the third year following promulgation of the HCl standard. These are substantial reductions with substantial public health benefits . Although MACT standards may only address HAP, not criteria pollutants, Congress fully expected MACT standards to have the collateral benefit of controlling criteria pollutants as well, and viewed this as an important benefit of the air toxics program

. 8

Alt hough we are not proposing this approach for the reasons discussed above, we request comment on a health

- based compliance alternative for HCl and/or manganese and other informat ion on HCl and manganese health and environmental effects we should consider. Commenters should also address the issue of other environmental benefits which might result from It, therefore, is appropriate that EPA consider such benefits as a factor in determinin g whether to exercise its discretionary CAA section 112 (d)(4) authority.

8 See S. Rep. No. 101

- 228, 101 st Cong. 1 st sess. At 172129 control of HCl and manganese at MACT levels, including control of other acid gas es and metals and control of secondary PM (i.e., PM condensing from acid gases). We will consider these comments in making an ultimate determination as to whether to adopt a health

- based compliance alternatives for HCl or
manganese.
K
. How did we select the compliance requirements ? We are proposing testing, monitoring, notification, and recordkeeping requirements that are adequate to assure continuous compliance with the requirement of th is proposed rule. Th e se requirements are described in detail in se ctions

IV. K to IV. N . We selected these requirements based upon our determination of the information necessary to ensure that the emission standards and work practices are being followed and that emission control devices and equipment are maintained and

op erated properly. The se proposed requirements ensure compliance with th is proposed rule without im posing a significant additional burden for facilities that must implement them. We are proposing that compliance with the emission limits for PM , HCl, mercur y, CO , and D/F be demonstrated by an initial performance test. To ensure continuous compliance with the proposed PM , HCl, and mercury emission limits, th is proposed130 rule would require continuous parameter monitoring of control devices and recordkeeping. Additionally, th is proposed rule would require annual performance tests to ensure, on an ongoing basis, that the air pollution control device is operating properly and its performance has not deteriorated. If initial compliance with the mercury and/or HCl emission limit s are demonstrated by a fuel analysis performance test, th is proposed rule would require fuel analyses monthly, with compliance determined based on an annual average. We evaluated the feasibility and cost of applying PM CEMS to boilers and process heaters

. CEMS have been used in Europe to monitor PM emissions from a variety of industrial sources. Several electric utility companies in the United States have now installed or are planning to install PM CEMS. In recognition of the fact that P M CEMS are commercially available, EPA developed and promulgated Performance Specifications (PS) for PM CEMS (69 FR 1786, January 12, 2004). PS for PM CEMS are established under PS

- 11 in appendix B to 40 CFR part 60 for evaluating the acceptability of a P M CEM used for determining compliance with the emission standards on a continuous basis. For PM CEM monitoring, capital costs were estimated to be $88,000 per unit and annualized costs were estimated to be $33,000 per unit. We determined that requiring P M CEMS for units with heat input131 capacity greater or equal to 250 MMBtu/hr and combusting either coal, biomass, or oil is a reasonable monitoring option. We are requesting comment on the application of PM CEMS to boilers and process heaters , and the use o f data from such systems for compliance determinations under this proposed rule. We reviewed cost information for CO CEMS to make the determination on whether to require CO CEMS or conducting annual
THC testing to demonstrate continuous compliance with th e THC emission limit. In evaluating the available cost information, we determined that requiring CO CEMS for units with heat input capacities greater or equal to 100 MMBtu/hr is reasonable. Th is proposed rule would require units with heat input capacitie s less than 100 MMBtu/hr to conduct initial and annual performance (stack) tests. The majority of test methods that th is proposed rule would require for the performance stack tests have been required under many other EPA standards. The only applicable voluntary consensus standard identified is ASTM Method D6784

- 02 ( Ontario Hydro )

. The majority of emissio ns tests upon which the proposed emission limits are based were conducted using these test methods. When a performance test is conducted , we are prop osing that

p arameter operating limits be determined during the tests.132

P erformance tests to demonstrate compliance with any applicable emission limits are either stack test s or fuel analysis or a combination of both. To ensure continuous compliance with t he proposed emission limits and/or operating limits, th is proposed rule would require continuous parameter monitoring of control devices and recordkeeping. We selected the following requirements based on reasonable cost, ease of execution, and usefulness of the resulting data to both the owners or operators and EPA for ensuring continuous compliance with the emission limits and/or operating limits. We are proposing that certain parameters be continuously monitored for the types of control devices commonly used in the industry. These parameters include opacity monitoring except for wet scrubbers; pH, pressure drop and liquid flowrate for wet scrubbers; and sorbent injection rate for dry scrubbers. You must also install a bag leak detection system for fabr ic filters. If you cannot monitor opacity for control systems with an ESP then you must monitor the secondary current and voltage or total power input for the ESP. These monitoring parameters have been used in other standards for similar industries. The values of these parameters are established during the initial or133 most recent performance test that demonstrates compliance. These values are your operating limits for the control device. You would be required to set parameters based on 4

- hour block aver ages during the compliance test, and demonstrate continuous compliance by monitoring 12

- hour block average values for most parameters. We selected this averaging period to reflect operating conditions during the performance test to ensure the control syst em is continuously operating at the same or better level as during a performance test demonstrating compliance with the emission limits. To demonstrate continuous compliance with the emission and operating limits, you would also need daily records of the quantity, type, and origin of each fuel burned and hours of operation of the affected source. If you are complying with the chlorine fuel input option, you must keep records of the calculations supporting your determination of the chlorine content in the fuel. If a source elect ed to demonstrate compliance with the HCl

or mercury limit by using fuel which has a statistically lower pollutant content than the emission limit, we are proposing that the source’s operating limit is the emission limit of the appl icable pollutant. Under this option, a source is not required to conduct performance stack tests. If a source134
demonstrate s compliance with the HCl or mercury limit by using fuel with a statistically higher pollutant content than the applicable emission l imit, but performance tests demonstrate that the source can meet the emission limits, then the source’s operating limits are the operating limits of the control device (if used) and the fuel pollutant content of the fuel type/mixture burned. Th is proposed rule would specif y the testing methodology and procedures and the initial and continuous compliance requirements to be used when complying with the fuel analysis options. Fuel analysis tests for total chloride, gross calorific value, mercury, sample coll ection, and sample preparation are included in th is proposed rule. If you elect to comply based on fuel analysis, you will be required to statistically analyze, using the z

- test, the data to determine the 90 th percentile confidence level. It is the 90 th percentile confidence level that is required to be used to determine compliance with the applicable emission limit. The statistical approach is required to assist in ensuring continuous compliance by statistically accounting for the inherent variability i n the fuel type. We are proposing that a source be required to recalculate the fuel pollutant content only if it burn s a new fuel type or135
fuel mixture and conduct another p erformance test if the results of recalculating the fuel pollutant content are high er than the level established during the initial performance test. For boilers and process heaters with heat input capacities greater or equal to 100 MMBtu/hr, we are proposing that C O be continuously monitor ed to demonstrate that average C O emissions,

on a 30

- day rolling average, are at or below the proposed CO limit

. For boilers and process heaters with heat input capacities between 10 and 100 MMBtu/hr, we are proposing that a performance stack tes t of C O emissions be conducted to demonstrate compliance with the C O emission limit.

L
. What alternative compliance provisions are being proposed? We are proposing that owners and operators of existing affected sources may demonstrate compliance by emissions averaging for units at the affected source that are within the

same a single subcategory

. A s part of the EPA’s general policy of encouraging the use of flexible compliance approaches where they can be properly monitored and enforced, we are includ ing emissions averaging in th is proposed rule. Emissions ave raging can provide sources the flexibility to comply in the least costly manner while still maintaining regulation that is workable and enforceable.136
Emissions averaging would not be applicable to new sources and could only be used between boilers and proc ess heaters in the same subcategory

. at a particular affected source

. Also, owners

or operators of existing sources subject to the Industrial Boiler NSPS (40 CFR part 60, subparts Db and Dc) would be required to continue to meet the PM emission standard o f that
NSPS regardless of whether or not they are using emissions averaging. Emissions averaging would allow owners and operators of an affected source to demonstrate that the source complies with the proposed emissions limits by averaging the emissions f rom an individual affected unit that is emitting above the proposed emission limit s to comply with th e emission limit s by averaging its emissions with other affected units at the same facility that are emitting below the proposed emission limit s . Th is pro posed rule would include include s an emissions averaging compliance alternative because emissions averaging represents an equivalent, more flexible, and less costly alternative to controlling certain emission points to MACT levels. We have concluded that a limited form of averaging could be implemented and that would not lessen the stringency of the standard MACT floor limits and would provide flexibility in compliance, cost and energy savings to owners and operators. We137
also recognize that we must ensure th at any emissions averaging option can be implemented and enforced, will be clear to sources, and most importantly, will achieve be no less emissions reductions stringent than unit by unit implementation of the MACT requirements floor limits

. Th is proposed ru le would not be the first NESHAP to include provisions permitting emission averaging. In general, EPA has concluded that it is permissible to establish within a NESHAP a unified compliance regimen that permits averaging within an affected source across i ndividual affected units subject to the standard under certain conditions. Averaging across affected units is permitted only if it can be demonstrated that the total quantity of any particular HAP that may be emitted by that portion of a contiguous major source that is subject to the NESHAP will not be greater under the averaging mechanism than it c ould be if each individual affected unit complied separately with the applicable standard. Under this test, the practical outcome of averaging is equivalent to compliance with the MACT floor limits by the each discrete units unit , and the statutory policy embodied in the MACT floor provisions requirement that the MACT standard reflect the maximum achievable emissions reductions is, therefore, fully effectuated.138

I n past rulemakings, EPA has generally imposed certain limits on the scope and nature of emissions averaging programs. These limits include: (1) No averaging between different types of pollutants, (2) no averaging between sources that are not part of the s ame major affected source, (3) no averaging between individual sources within the same a single major source that if the individual sources are not subject to the same NESHAP, and (4) no averaging between existing sources and new sources. Th is proposed rule would fully satisf y each of these criteria. First, emissions averaging would only be permitted between individual sources at a single existing affected source, and would only be permitted between individual sources subject to the boiler and process heater NESHAP. Further, emissions averaging would not be permitted between two or more different affected sources. Finally, new sources could not use emissions averaging. Accordingly, we have concluded that the averaging of emissions across affected units is consistent with the CAA. In addition, the provision in th is proposed rule would require each facility that intends to utilize emission averaging to submit an emission averaging plan , which provide s additional assurance that the necessary criteria will be followed. In this emission averaging plan, the facility must include the identification of139 (1) all units in the averaging group, (2) the control technology installed, (3) the process parameter that will be

monitored, (4) the specific control technology o r pollution prevention measure to be used, (5) the test plan for the measurement of the HAP being averaged , and (6) the operating parameters to be monitored for each control device. Upon receipt, the regulatory authority will would not be able to

approve a n emission averaging plan containing averaging between emissions of different types of pollutants or between sources in different subcategories. Th is proposed rule would also exclude new affected sources from the emissions averaging provision. New source s have historically been held to a stricter standard than existing EPA believes emissions averaging is not appropriate for n ew sources because it is most cost effective to integrate state

- of

- the

- art controls into equipment design and to install the techno logy during construction of new sources. One reason we allow emissions averaging is to give existing sources flexibility to achieve compliance at diverse points with varying degrees of add

- on control already in place in the most cost

- effective and technic ally reasonable fashion. This concern does flexibility is

not apply to needed for new sources which because they can be designed and constructed with compliance in mind.140 With concern about the equivalency of emissions reductions from averaging and non

- averag ing in mind, we are also proposing under the emission averaging provision caps on the current emissions from each of the sources in the averaging group. The emissions for each unit in the averaging group would be capped at the emission level being achieve d on the effective date of the final rule. These caps would ensure that emissions do not increase above the emission levels that sources currently are designed, operated, and maintained to achieve. In the absence of performance tests, in documenting thes e caps, these sources will document the type, design, and operating specification of control devices installed on the effective date of the final rule to ensure that existing controls are not removed or lessen. By including this provision in th is proposed rule, we have taken yet another step to assist in ensuring would further ensure that emission averaging results in environmental benefits equivalent

or better over what would have happened without emission averaging. In addition, we are proposing that a d iscount factor of ten percent would be applied when emissions averaging is used. This discount factor will further ensure that averaging will be at least as stringent as the MACT floor limits in the absence of averaging. The emissions averaging provision would not apply to14 1
individual units if the unit shares a common stack with units in other subcategories, because in that circumstance it is not possible to distinguish the emissions from each individual unit.

M
. How did EPA determine compliance times for the proposed rule ? Section 112 of the CAA specifies the dates by which affected sources must comply with the emission standards. New or reconstructed units must be in compliance with th is proposed rule immediately upon startup or [DATE THE FINAL RULE IS
PUBLISHED IN THE FEDERAL REGISTER ], whichever is later. Existing sources are allowed 3 years to comply with the final rule. This is the maximum period allowed by the CAA. We believe that 3 years for compliance is necessary to allow adequate time to des ign, install and test control systems that will be retrofitted onto existing boilers, as well as obtain permits for the use of add

- on controls.

N
. How did EPA determine the required records and reports for th is proposed rule ? You would be required to com ply with the applicable requirements in the NESHAP General Provisions, subpart A of 40 CFR part 63, as described in Table 10 of the proposed subpart DDDDD. We evaluated the General Provisions requirements and included those we determined to be the minimum notification,142 recordkeeping, and reporting necessary to ensure compliance with, and effective enforcement of, th is proposed rule. We are also requiring that you keep daily records of the total fuel use by each affected source, subject to an emission li mit or work practice standard, along with a description of the fuel, the total fuel usage amounts and units of measure, and information on the supplier and original source of the fuel. This information is necessary to ensure that the affected source is co mplying with the emission limits from the correct subcategory.

We would requir e additional recordkeeping if you chose to comply with the chlorine or mercury fuel input option. You would need to keep records of the calculations and supporting information used to develop the chlorine or mercury fuel input operating limit.
O
. How does th is proposed rule affect permits ? The CAA requires that sources subject to th is proposed rule be operated pursuant to a permit issued under EPA

- approved State operating perm it program. The operating permit programs are developed under title V of the CAA and the implementing regulations under 40 CFR parts 70 and 71. If you are operating in the first 3 years of your operating permit, you will need to obtain a revised permit t o incorporate th is proposed rule. If143 you are in the last 2 years of your operating permit, you will need to incorporate th is proposed rule into the next renewal of your permit.

P. Alternate Standard for Consideration The As discussed above, EPA is propo sing a definition of

“ non - hazardous secondary materials” is being proposed solid waste under RCRA in a concurrent notice under RCRA; this RCRA proposal also identifies an “alternative approach”

. The proposed CAA section 112(d) standards for consideration and comment. The concurrently boilers and process heaters are based on that proposed RCRA non

- hazardous secondary materials definition is integral in defining of solid waste. Therefore,

t he ICI boiler and process heater source categor ies

. T he emission l imits presented in Tables 1 through 5 above are based on subcategories established considering sources that are ICI boilers and process heaters under the “ proposed approach” definition being proposed concurrently of solid waste under RCRA. The “ However, the RCRA proposal also identifies and solicits

comment on an alternative approach for defining solid waste, under which more units would be considered solid waste incineration units than under the proposed definition. As such,

t he alternative approach ” id entified for consideration and comment in the concurrently proposed RCRA notice for defining144
solid waste under RCRA would result in a different , smaller population of units being covered by Boiler MACT

. We Consistent with EPA’s solicitation of comment o n an alternative proposed definition of solid waste under RCRA, w e calculated MACT floors using emission rates for units that would be ICI boilers and process heaters under the “ th at alternative approach” and definition, using the same statistical procedure s previously described above . Table 6 reflects the potential that calculation of MACT floor limi ts for the existing source subcategories that would be affected considering changed by the

“ alternative approach” definition of solid waste identified in the con current RCRA proposal , compared to the proposed definition of solid waste in that proposal . The MACT floor limits for the remaining existing source subcategories (Gas 1, Gas 2, and Liquid) would not change under the “ alternative approach” identified for c onsideration and definition of solid waste on which EPA is soliciting comment in a the concurrent RCRA proposal under RCRA , and are reflected therefore not included in Table 1 of today’s notice. 8 because the MACT floor limits for those subcategories would be the same under the alternative definition of solid waste as under the proposed definition

**TABLE 6**  **. 8**  **. EXISTING MACT FLOOR LIMITS USING THE “ALTERNATIVE**  **APPROACH” UNDER CONSIDERATION AND COMMENT IN THE CONCURRENTLY PROPOSED RCRA RULE**  (pounds per million British thermal units)145

Subcategory Particulate Matter (PM) Hydrogen Chloride

(HCl) Mercury (Hg) Carbon Monoxide(CO) (ppm @3%oxygen) Dioxins/ Furans (Total TEQ) (ng/dscm) @ 7%O2 Existing

– Coal Stoker 0.02 0.008 0.000003 30 0.00 29
Existing

- Coal Fluidi zed Bed 0.02 0.008 0.000003 40 0.0073

Existing

– Pulverized Coal 0.02 0.008 0.000003 70 0.00 38

Existing

– Biomass Stoker 0.0 2 0.0 3 0.000000 4 540 0.000 049

Existing

- Biomass Fluidized Bed 0.0 2 0.0 3 0.000000 4 10,650 0.09 3

Existing

– Biomass Suspension Burner/Dutc h Oven 0.0 2 0.0 3 0.000000 4 1,430 0.6 1

Existing

– Biomass Fuel Cells 0.0 2 0.0 3 0.000000 4 460 0.06 2

Exist ing

– Metal Industry Process Heaters -- -- -- -- --

Comparing the emissions limits in Table 1 (based on the proposed definition of solid waste) with those in Table 6 ( 8 (based on the alternative approach definition of solid waste ), the MACT emission limits for PM and mercury for the biomass subcategories would be less stringent if they are higher146
under based on the “ alternative approach” defi nition of solid

waste while the HCl emission limits for the coal and biomass subcategories are would be more stringent under if they are based

on the “ alternative approach.” definition. The potential emissions reductions if the MACT floor limits are calcula ted based on this “ the alternative approach” are definition of solid waste would be generally lower due to than the potential emissions reductions for MACT floors based on the proposed definition of solid waste, because 281 fewer boilers and process heater s that would be considered CISWI units subject to the boiler and process heater MACT standards under the

“ alternative approach.” definition. These units would instead be considered CISWI units under the alternative definition of solid

waste. For example, m ercury emissions reduction would be 17 tons per year instead of based on the alternative definition of solid waste (compared to 19 tons per year based on the proposed definition) and HCl emissions reduction would be 44,000 tons per

year instead of based on the alternative definition (compared to 47,000 tons per year

. based on the proposed definition). Most (181) of the 281 units that would be considered CISWI units under the alternative definition of solid waste proposed under
RCRA are biomass

- fired boiler s or process heaters, with the others being in the coal and liquid fuel subcategories.147 The resulting total national cost impact of the proposed emission limits based on the “ alternative approach” is definition of solid waste would be 11.3 billion dollars in capital expenditures and 4.3 billion dollars per year in total annual costs. This compares to $13.5 billion in capital costs and $5.4 billion in annual costs under the “ proposed approach” definition of solid waste in the RCRA proposed rule. Table 6a 9 o f this preamble shows the capital and annual cost impacts for each subcategory under the alternative definition of solid waste

. Costs include testing and monitoring costs, but not recordkeeping and reporting costs.

TABLE 6a. 9

. SUMMARY OF CAPITAL AND ANNUA L COSTS FOR EXISTING SOURCES UNDER THE ALTERNATIVE SOLID WASTE DEFINITION

Source Subcategory Estimated/ Projected

No. of Affected

Units Capital Costs (10 6 $) Annualized Cost (10 6 $/yr)

Existing Uni ts Coal units 524 3,850 1,484 Biomass units 239 1,324 359 Liquid units 796 2,153 658
Gas (NG/RG) units 11,402 2,674 1,399
Gas (other) units 193 1,298 387

Energy Audit ALL 1,550 facilities 24.9 Formatted: Font: 10 pt148 A discussion of the methodology used to estimate c ost impacts is presented in “Methodology and Results of Estimating the Cost of Complying with the Industrial, Commercial, and Institutional Boiler and Process Heater NESHAP (2010)” in the Docket.

We are also proposing soliciting public comments on the emis sion limits listed in Table 6 of this preamble as an alternate in case public , consistent with EPA’s solicitation of comments on the alternative definition of solid waste concurrently proposed under RCRA rule warrant promulgation of

. As explained above, the emissions MACT floor limits proposed today are based on the “alternative approach.” Therefore, we proposed definition of solid waste under RCRA. However, because EPA is seeking comment on an alternative definition of solid waste under RCRA, the Agency believes it is necessary to also solicit comment on what the emission s MACT floor limits listed in Table 6 of this preamble would be based on the universe of sources that would be subject to the boiler and process heater MACT under that alternative definiti on . **V. Impacts of the Proposed Rule**

A. What are the air impacts ? Table 7 10 of this preamble illustrates, for each basic fuel subcategory, the emissions reductions achieved by the proposed149 rule (i.e., the difference in emissions between a boiler or

proc ess heater controlled to the floor level of control and boilers or process heaters at the current baseline) for new and existing sources. Nationwide emissions of selected HAP (i.e., HCl, HF, mercury, metals, and VOC) will be reduced by 53,560 48 , 600 tons p er year for existing units and 67 15 tons per year for new units. Emissions of HCl will be reduced by 47,0 00 4 2 , 4 00 tons per year for existing units and 52 9 tons per year for new units. Emissions of mercury will be reduced by 1 9 8 tons per year for existing units and 12 2 .6 pounds per year for new units. Emissions of filterable PM will be reduced by
42 50 , 100 tons per year for existing units and 140 1 3 0 tons per year for new units. Emissions of non

- mercury metals (i.e., antimony, arsenic, beryllium, cadmium, chromium, cobalt, lead, manganese, nickel, and selenium) will be reduced by 3, 900 2 00 tons per year for existing units and will be reduced by 1,380 pounds 0. 6 ton per year for new units. In addition, emissions of
SO 2 are established to be reduced by 383, 3 60 , 0 00 tons per year for existing sources and 5 0 0 tons per year for existing sources and 550 tons per year for new sources. Emissions of dioxin/furans, on a total mass basis, will be reduced by 844 72 2 grams per year for exi sting units and 2 grams 1 gram per year for new units. A discussion of the methodology used to estimate150 emissions and emissions reductions is presented in “Estimation of Baseline Emissions and Emissions Reductions for Industrial, Commercial, and Institutional Boilers and Process Heaters (2 010)” in the docket.

TABLE 7

. 10

. SUMMARY OF EMISSIONS REDUCTIONS FOR EXISTING AND NEW SOURCES (TONS/YR) b

Source Subcategory HCl PM Non Mercury Metals a Mercury b VOC Existing Units Coal units 40, 600 7 00 17,000 879 7 70 15,300 7 510 47 0

Biomass units 1,600 52 0 13,700 2 2,5 00 133 230 430 0.2 334 760 Liquid units 4,500 95 0 11,300 1 0,4 00 2, 900 2 0 0 204 0.00 005 325 290

Gas 1 (NG/RG) units 47 9 130 1. 2 1 21,670 0 .4 53 72

Gas 2 (other)units 234 2 20 0 0 337 0.2 210 170

New Units Coa l units 0 0 0 0 0 Biomass units 0 0 0 0 0 Liquid units 43 9 130 0.6 10 0 3 Gas 1 units 9 0 5 0 0 .04 2 0 1 0 Gas 2 units 1 5 4 0. 02 0 1 1 0 1

a Includes antimony, arsenic, beryllium, cadmium, chromium, cobalt, lead, manganese, nickel, and sele nium. b Emission reductions for mercury are presented in units of pounds per year.

B. What are the water and solid waste impacts ?151 The EPA estimated the additional water usage that would result from installing wet scrubbers to meet the emis sion limits for HCl would be 3,200 2,8 00 million gallons per year for existing sources and 1.2 million 200,000 gallons per year for new sources. In addition to the increased water usage, an additional 944 842 million gallons per year of wastewater would be p roduced for existing sources and 79 0 140 ,000 gallons per year for new sources. The annual costs of treating the additional

wastewater are $ 5.1 4.6 million for existing sources and $ 4, 3 00 774 for new sources. These costs are accounted for in the control cost s estimates. The EPA estimated the additional solid waste that would result from the MACT floor level of control to be 250 81 ,000 tons per year for existing sources and 3 , 1 00 149,8 00 tons per year for new sources. Solid waste is generated from flyash and d ust captured in PM and mercury controls as well as from spent carbon that is injected into exhaust streams or used to filter gas streams. The costs of handling the additional solid waste generated are $ 10.5 3.4 million for existing sources and $ 130,600 6.3 m illion for new sources. These costs are also accounted for in the control costs estimates. A discussion of the methodology used to estimate impacts is presented in “Estimation of Impacts for Industrial, Commercial,152
and Institutional Boilers and Process H eaters NESHAP (2010)” in the Docket.
C. What are the energy impacts ? The EPA expects an increase of approximately 3, 90 1 160 million kilowatt hours (kWh) in national annual energy usage as a result of the proposed rule. Of this amount, 3, 889 149 million kW h would be from existing sources and 12 1 1 million kWh are estimated from new sources. The increase results from the electricity required to operate control devices, such as wet scrubbers, electrostatic precipitators, and fabric filters which are expected to be installed to meet the proposed rule. Additionally, the EPA expects work practice standards such as boilers tune

- ups and combustion controls will improve the efficiency of boilers, resulting in an estimated fuel savings of
41 4 2 t rillion BTU each year from existing sources and an additional 168 1 00 ,000 million BTU each year. This fuel savings estimates includes only those fuel savings resulting from gas, liquid, and coal fuels and it is based on the assumption that the work practice standards will achiev e 1% improvement in efficiency.

D. What are the control costs ? To estimate the national cost impacts of the proposed rule for existing sources, we developed average baseline emission153 factors for each fuel type/control device combination based on the emis sion data obtained and contained in the Boiler MACT emission database. If a unit reported emission data, we assigned its unit

- specific emission data as its baseline emissions. For units that did not report emission data, we assigned the appropriate emissi on factors to each existing unit in the inventory database, based on the average emission factors for boilers with similar fuel, design, control devices. We then compared each unit’s baseline emission factors to the proposed MACT floor emission limit to de termine if control devices were needed to meet the emission limits. The control analysis considered fabric filters, carbon bed adsorbers, and activated carbon injection to be the primary control devices for mercury control, electrostatic precipitators for units meeting mercury limits but requiring additional control to meet the PM limits, wet scrubbers to meet the HCl limits, tune

- ups, replacement burners, and combustion controls for CO and organic HAP control, and carbon injection for dioxin/furan control. We identified where one control device could achieve reductions in multiple pollutants, for example a fabric filter was expected to achieve both PM and mercury control in order to avoid overestimating the costs. We also included costs for testing and moni toring requirements contained in the proposed rule. The resulting total154 national cost impact of the proposed rule is 1 3

. 5 1 0

. 0 billion dollars in capital expenditures and 3

. 5

. 4 billion dollars per year in total annual costs. Considering estimated fuel savi ngs resulting from work practice standards and combustion controls, the total annualized costs are reduced to 5 3 .1 billion. The total capital and annual costs include costs for control devices, work practices, testing and monitoring. Table 8 11 of this pr eamble shows the capital and annual cost impacts for each subcategory. Costs include testing and monitoring costs, but not recordkeeping and reporting costs.

TABLE 8

. 11

. SUMMARY OF CAPITAL AND ANNUAL COSTS FOR NEW AND EXISTING SOURCES

Source Subcategory Estimated/ Projected

No. of Affected

Units Capital Costs (10 6 $) Testing and Monitoring Annualized Costs (10 6 $/yr) Annualized Cost (10 6 $/yr)

Existing Units Coal units 577 578 4, 542 880 62.6 1, 665 854 Biomass units 420 2, 646 003 37.1 880 613 Liquid units 831 826 2,245 1,48 7 30.7 694 503
Gas (NG/RG) units 11, 411 532 2,674 75 0 1,396 33
Gas (other) units 196 199 1, 367 554 10.2 407 481

Energy Audit ALL 26

New Units Coal units 0 0 0 0155

Biomass units 0 0 0 0 Liquid units 11 12 0.5 5.8 6.1
Gas (NG/RG) units 32 33 43.6 0.2 0 18.9 0.01
Gas (other) units 2 6.3 5.5 0.14 1.7

Using Department of Energy projections on fuel expenditures, the number of additional boilers that could be potentially constructed was estimated. The resulting total national cost impact of the proposed rule in the 3rd year is 62 17 million dollars in capital expenditures and 26.4 6. 2 million dollars per year in total annual costs, when considering a 1 percent fuel savings. Potential con trol device cost savings and increased recordkeeping and reporting costs associated with the emissions averaging provisions in the proposed rule are not accounted for in either the capital or annualized cost estimates. A discussion of the methodology used to estimate cost impacts is presented in “Methodology and Results of Estimating the Cost of Complying with the Industrial, Commercial, and Institutional Boiler and Process Heater NESHAP (2010)” in the Docket.

E
. What are the economic impacts ?156
The econom ic impact analysis (EIA) that is included in the RIA shows that the expected prices for industrial sectors could be 0.01 percent higher and domestic production may fall by about 0.01 percent . Because of higher domestic prices imports may rise by 0.01 perc ent . In addition, impacts to affected energy markets show that prices may rise by 0.2 percent. Social costs are estimated to also be $5. 1 billion in 2008 dollars. This is estimated to be made up of a $ 1.8 billion loss in domestic consumer surplus, a $3. 8 billion loss in domestic producer surplus, a $0.2 billion increase in rest of the world surplus, and a $0.4 3 billion in net fuel savings not modeled in a way that can be used to attribute it to consumers and producers. EPA performed a screening analysis for impacts on small entities by comparing compliance costs to sales/revenues (e.g., sales and revenue tests). EPA’s analysis found the tests were typically higher than 3% for small entities included in the screening analysis. EPA has prepared an Initial Regulatory Flexibility Analysis (IRFA) that discusses alternative regulatory or policy options that minimize the rule’s small entity impacts. It includes key information about key results from the Small Business Advocacy Review (SBAR) panel.157 Estimates of job changes were developed in two different ways. The first is based on assuming job changes proportional to output changes. This approach provides a point estimate of 8,000 less jobs; data is not available to estimate uncertainty ranges. T his does not include job increases associated with pollutant abatement activities that require additional labor to produce the same level of output or changes related to post regulation production technologies. The second approach is more comprehensive an d looks more directly at all three components but is based on a limited set of industrial data. This second method showed a point estimate of a net increase of about 8,000 in jobs. However, statistical analysis of the data indicates that we can not state whether the net change will be an increase or a decrease using the second method.

F
. We estimate the monetized benefits of this proposed regulatory action to be $16 billion to $40 billion (2008 $, 3 percent discount rate) in the implementation year (2013). The monetized benefits of the proposed regulatory action at a 7 percent discount rate are $15 billion to $36 billion (2008$). Using alternate relationships between PM 2.5 and premature mortali ty supplied by experts, higher and lower benefits estimates are plausible, but most of the expert

- based estimates What are the social costs and benefits of this proposed rule ?158
fall between these two estimates. 9

TABLE 9

. 12

. Summary of the Monetized Benefits Estimates for the Proposed Boiler MACT for Major Sources in 2013 (billions of 2008$) 1 A summary of the monetized benefits estimates at discount rates of 3 percent and 7 percent is in Table 9 12 of this preamble.

Estimated Emission reductions (tons per year) Total monetized benefits (3% Discount Rate) Total moneti zed benefits (7% Discount Rate) 22,6 62 tons PM 2.5 384,0 24 tons SO 2

1,43 6 tons VOC $16 to $40 $15 to $36

1 All estimates are for the implementation year (2013), and are rounded to two significant figures so numbers may not sum across rows. All fine partic les are assumed to have equivalent health effects, but the benefit

- per - ton estimates vary between precursors because each ton of precursor reduced has a different propensity to form PM 2.5 . Benefits from reducing hazardous air pollutants (HAPs) are not inc luded.
These benefits estimates represent the total monetized human health benefits for populations exposed to less PM 2.5 in 2013 from controls installed to reduce air pollutants in order to meet these standards. These estimates are calculated as the

s um of the monetized value of avoided premature mortality and morbidity associated with reducing a ton of PM 2.5 and PM 2.5 precursor emissions. To estimate of human health benefits derived from reducing PM 2.5 and PM 2.5 precursor emissions, we

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

– 2274.159 utilized the ge neral approach and methodology on the laid out in Fann et al. (2009) 10 To generate the benefit

- per - ton estimates, we used a model to convert emissions of direct PM 2.5 and PM 2.5 precursors into changes in ambient PM 2.5 levels and another model to estimate the changes in human health associated with that change in air quality. Finally, the monetized health benefits were divided by the emission reductions to create the benefit

- per - ton estimates. Even though we assume that all fine particles have equivalent health effects, the benefit

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

per - ton estimate than direct PM 2.5 because it does not form as much PM 2.5 , thus the exposure would be lower, and the monetized health benefits would be lower. .

For context, it is important to note that the magnitude of the PM benefits is largely driven by the concentration response function for premature mortality. Expe rts have advised EPA to consider a variety of assumptions, including estimates based both on empirical (epidemiological) studies and judgments elicited from scientific experts, to characterize the

10 Fann, N., C.M. Fulcher, B.J. Hubbell. 2009. The influence of location, source, and emission type in estimates of the human health benefits of reducing a ton of air pollution. Air Qual Atmos Health (2009) 2:169

– 176.160 uncertainty in the relationship between PM 2.5 concentration s and premature mortality. For this proposed rule we cite two key empirical studies, one based on the American Cancer Society cohort study 11 and the extended Six Cities cohort study 12

This analysis does not include the type of detailed uncertainty assessment found in the 2006 PM 2.5 NAAQS RIA because we lack the necessary air quality input and monitori ng data to run the benefits model. However, the 2006 PM 2.5 NAAQS benefits analysis . In the RIA for this proposed rule, which is available in the docket, w e also include benefits estimates derived from expert judgments and other assumptions.

13

It should be emphasized that the monetized benefits estimates provided above do not incl ude benefits from several important benefit categories, including reducing other air pollutants, ecosystem effects, and visibility impairment. The benefits from reducing carbon monoxide and hazardous air provides an indication of the sensitivity of our results to various assumptions.

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

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

- 1141 12 Laden et al, 2006. “Reduction in Fine Particulate Air Pollution and Mortality.” American Journal of Respiratory and Critical Care Medicine. 173: 667

- 672 13 U.S. Environmental Protection Agency , 2006. Final Regulatory Impact Analysis: PM 2.5 NAAQS. Prepared by Office of Air and Radiation. October. Available on the Intern et at h ttp://www.epa.gov/ttn/ecas/ria.html161 pollutants have not been monetized in this analysis , including reducing 360,000 tons of carbon monoxide, 19 tons of mercury, 47,000 tons of HCl, and 1,200 tons of HF each year. Although we do not have sufficient information or modeling available to provide monetized estimates for this rulemaking, we inclu de a qualitative assessment of the health effects of these air pollutants in the Regulatory Impact Analysis (RIA) for this proposed rule, which is available in the docket. The social costs of this proposed rulemaking are estimated to be $5.1 billion (2008$ ) in the implementation year, and the monetized benefits are $16 billion to $4 0 billion (2008$, 3 percent discount rate) for that same year. The benefits at a 7 percent discount rate are $15 billion to $36 billion (2008$). Thus, net benefits of this rule making are estimated at $11 billion to $35 billion (2008$, 3 percent discount rate) and $9.8 billion to $31 billion (2008$, 7 percent discount rate). EPA believes that the benefits of the proposed rule are likely to exceed the costs even when taking into account the uncertainties in the cost and benefit estimates. For more information on the benefits analysis, please refer to the RIA for this rulemaking, which is available in the docket.

**V I. Public Participatio**  **n and Requests for Comment**162 We request comme nt on all aspects of this propos ed rule

. In 200 4 we published a final rule for boilers and process heaters located at major source facilities ( 6 9 FR 55218 , September 13, 2004 ). The final rule was vacated by the Court on June 19, 2007. We are reissuing our proposal , in response to the Court’s decisions, in this notice. We received many comments on that vacated rule during its rulemaking and have attempted to take all those comments into account in this action. This proposal includes a variety of change s from the vacated rule , mostly centered on emission limits for the various HAP and subcategories

. During this rulemaking, we conducted outreach to small entities and convened a Small Business Advocacy Review ( SBAR ) Panel to obtain advice and recommendati on of representatives of the small entities that potentially would be subject to the requirements of this proposed rule. As part of the SBAR Panel

process we conducted outreach with representatives from various small entities that would be affected by thi s proposed rule. We met with these small entity representatives ( SERs ) to discuss the potential rulemaking approaches and potential options to decrease the impact of the rulemaking on their industries /sectors

. We distributed outreach materials to the
SER s; these materials included background on the rulemaking,163 possible regulatory approaches, preliminary cost and economic impacts, and possible rulemaking alternatives. We met with SERs from the industries that will be impacted directly by this proposed rul e t o discuss the outreach materials and receive feedback on the approaches and alternatives detailed in the outreach packet. The Panel received written comments from the SERs following the meeting in response to discussions at the meeting and the question s posed to the SERs by the Agency. The SERs were specifically asked to provide comment on regulatory alternatives that could help to minimize the rule’s impact on small businesses.

**VI I**  **. Relationship of th is**  **Proposed Action to**  **Section 112(c)(6) of the CAA**  Section 112(c)(6) of the CAA requires EPA to identify categories of sources of seven specified pollutants to assure that sources accounting for not less than 90 percent of the aggregate emissions of each such pollutant are subject to standards under CAA Se ction 112(d)(2) or 112(d)(4). EPA has identified “Industrial Coal Combustion,” “Industrial Oil Combustion,” Industrial Wood/Wood Residue Combustion,” “Commercial Coal Combustion,” “Commercial Oil Combustion,” and “Commercial Wood/Wood Residue Combustion” as source categor ies that emits two of the seven CAA Section 112(c)(6) pollutants:164

POM and mercury

. (The POM emitted is composed of 16 polyaromatic hydrocarbons and extractable organic matter .) In the Federal Register notice Source Category Listing for S ection 112(d)(2) Rulemaking Pursuant to Section 112(c)(6) Requirements, 63 FR 17838, 17849, Table 2 (1998), EPA identified “Industrial Coal Combustion,” “Industrial Oil Combustion,” “ Industrial Wood/Wood Residue Combustion,” “Commercial Coal Combustion,” “ Commercial Oil Combustion,” and “Commercial Wood/Wood Residue Combustion” as source category “ subject to regulation ” for purposes of CAA Section 112(c)(6) with respect to the CAA Section 112(c)(6) pollutants that these units emit. Specifically, as byproduc ts of combustion, the formation of POM is effectively reduced by the combustion and post

- combustion practices required to comply with the CAA Section 1 1 2 standards. Any POM that do form during combustion are further controlled by the various post

- combusti on controls. The add

- on PM control systems (either fabric filter or wet scrubber) and activated carbon injection in the fabric filter

- based systems further reduce emissions of these organic pollutants, and also reduce

mercury emissions, as is evidenced by performance data. Specifically, the emission tests obtained at currently165 operating units show that the proposed MACT regulations will reduce mercury emissions by about 86 percent. It is, therefore, reasonable to conclude that POM emissions will be subst antially controlled. Thus, while th is proposed rule does not identify specific numerical emission limits for POM , emissions of POM are, for the reasons noted below , nonetheless “ subject to regulation ” for purposes of Section 112(c)(6) of the CAA. In lieu of establishing numerical emissions limits for pollutants such as POM, CAA Section 129(a)(4) allows EPA to regulate surrogate substances. While we have not identified specific numerical limits for POM, we believe CO serves as an effective surrogate for t h i s HAP , because CO , like POM, is formed as a byproduct of combustion. Consequently, we have concluded that the emissions limits for CO function as a surrogate for control of POM, such that it is not necessary to pro pose numerical emissions limits for PO M

w ith respect to boilers and process heaters to satisfy CAA Section 112(c)(6). To further address POM and mercury emissions, th is proposed rule also includes an energy assessment provision that encourage modifications to the facility to reduce energy dema nd that lead to these emissions.

**V I**  **I I**  **. Statutory and Executive Order Reviews** 166

A. Executive Order 12866, Regulatory Planning and Review Under Executive Order 12866 (58 FR 51735, October 4, 1993), this action is an “economically significant regulatory acti on” because it is likely to have an annual effect on the economy of $100 million or more or adversely affect in a material way the economy, a sector of the economy, productivity, competition, jobs, the environment, public health or safety, or State, local, or tribal governments or communities. Accordingly, EPA submitted this action to the Office of Management and Budget (OMB) for review under EO 12866 and any changes in response to OMB recommendations have been documented in the docket for this action.

B. Executive Order 13132, Federalism Executive Order 13132 (64 FR 43255, August 10, 1999), requires EPA to develop an accountable process to ensure “meaningful and timely input by State and local officials in the development of regulatory policies that have federalism implications.” “Policies that have federalism implications” is defined in the Executive Order to include regulations that 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.167
Th is proposed rule does not have federalism implications. It will not have substantial direct effects on the States, on the relationship between the national governme nt and the States, or on the distribution of power and responsibilities among the various levels of government, as specified in Executive Order 13132. Thus, Executive Order 13132 does not apply to th is proposed rule. In the spirit of Executive Order 1313 2, and consistent with EPA policy to promote communications between EPA and State and local governments, EPA specifically solicited comment on th is proposed rule from State and local officials.
C. Executive Order 13175, Consultation and Coordination with Indian Tribal Governments Executive Order 13175 (65 FR 67249, November 9, 2000), requires EPA to develop an accountable process to ensure “meaningful and timely input by tribal officials in the development of regulatory policies that have tribal implicati ons.” Th is proposed rule does not have tribal implications, as specified in Executive Order 13175 (65 FR 67249, November 9, 2000). It will not have substantial direct effects on tribal governments, on the relationship between the Federal government and I ndian tribes, or on the distribution of power and responsibilities between the Federal government and Indian tribes, as specified in Executive Order 13175. Th is168 proposed rule imposes requirements on owners and operators of specified area sources and not t ribal governments. We do not know of any industrial, commercial, or institutional boilers owned or operated by Indian tribal governments. However, if there are any, the effect of th is proposed rule on communities of tribal governments would not be unique or disproportionate to the effect on other communities. Thus, Executive Order 13175 does not apply to th is proposed rule. EPA specifically solicits additional comment on th is proposed rule from tribal officials.

D. Executive Order 13045, Protection of Children from Environmental Health Risks and Safety Risks Executive Order 13045 (62 FR 19885, April 23, 1997) applies to any rule that: (1) is determined to be “economically significant” as defined under Executive Order 12866, and (2) concerns an environ mental health or safety risk that EPA has reason to believe may have a disproportionate effect on children. If the regulatory action meets both criteria, the Agency must evaluate the environmental health or safety effects of th is planned rule on children, and explain why th is planned regulation is preferable to other potentially effective and reasonably feasible alternatives considered by the Agency. Th is proposed rule is not subject to Executive Order 13045 because the Agency does not believe the environ mental health169 risks or safety risks addressed by this action present a disproportionate risk to children. The reason for this determination is that th is proposed rule is based solely on technology performance. The public is invited to submit comments or i dentify peer

reviewed studies and data that assess effects of early life exposure to th is proposed rule.

E. Unfunded Mandates Reform Act of 1995 Title II of the Unfunded Mandates Reform Act of 1995 (UMRA), Public Law 104

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

- benefit analysis, for

propos ed and final rules with “Federal mandates” that may result in expenditures to State, local, and tribal governments, in the aggregate, or to the private sector, of $100 million or more in any 1 year. Before promulgating a rule for which a written

statement is needed, section 205 of the UMRA generally requires us to identify and consider a reasonable number of regulatory alternatives and adopt the least costly, most cost

- effective or least burdensome alternative that achieves the objectives of the rule. The provisions of section 205 do not apply when they are170 inconsistent with applicable law. Moreover, section 205 allows us to adopt an alternative other than the least costly, most

cost

- effective or least burdensome alternative if the Administrator publishes with the final rule an explanation why that alternative was not adopted. Before we establish any regulatory requirements that may significantly or uniquely affect small governments, including tribal governments, we must develop a small government agency plan under section 203 of the UMRA. The plan must provide for notifying potentially affected small governments, enabling officials of affected small governments to have meaningful and timely input in the development of regulatory proposals with significan t Federal intergovernmental mandates, and informing, educating, and advising small governments on compliance with the regulatory requirements. We have determined that this proposed rule contains a Federal mandate that may result in expenditures of $100 mi llion or more for State, local, and Tribal governments, in the aggregate, or the private sector in any 1 year. Accordingly, we have prepared a written statement entitled “Unfunded Mandates Reform Act Analysis for the Proposed Industrial Boilers and

Proces s Heaters NESHAP" under section 202 of the UMRA which is summarized below.171
1. Statutory Authority As discussed in section I of this preamble, the statutory authority for this proposed rulemaking is section 112 of the CAA. Title III of the CAA Amendment s was enacted to reduce nationwide air toxic emissions. Section 112(b) of the CAA lists the 188 chemicals, compounds, or groups of chemicals deemed by Congress to be HAP. These toxic air pollutants are to be regulated by NESHAP. Section 112(d) of the CA A directs us to develop NESHAP which require existing and new major sources to control emissions of HAP using MACT based standards. This NESHAP applies to all industrial, commercial, and institutional boilers and process heaters located at major sources o f HAP emissions. In compliance with section 205(a) of the UMRA, we identified and considered a reasonable number of regulatory alternatives. Additional information on the costs and environmental impacts of these regulatory alternatives is presented in th e docket. The regulatory alternative upon which the proposed rule is based represents the MACT floor for industrial boilers and process heaters and, as a result, it is the least costly and least burdensome alternative. 2. Social Costs and Benefits172 The regulatory impact analysis prepared for the proposed rule including the Agency’s assessment of costs and benefits, is detailed in the “Regulatory Impact Analysis for the Proposed Industrial Boilers and Process Heaters MACT” in the docket. Based on estima ted compliance costs associated with the proposed rule and the predicted change in prices and production in the affected industries, the estimated social costs of the proposed rule are $5.1 billion (2008 dollars). It is estimated that 3 years after im plementation of the proposed rule, HAPs would be reduced by thousands of tons, including reductions in hydrochloric acid, hydrogen fluoride, metallic HAP including mercury, and several other organic HAP from boilers and process heaters. Studies have deter mined a relationship between exposure to these HAP and the onset of cancer, however, the Agency is unable to provide a monetized estimate of the HAP benefits at this time. In addition, there are significant reductions in PM 2.5 and in SO 2 that would occur, including 23 thousand tons of PM 2.5 and 384 thousand tons of SO 2 . These reductions occur within 3 years after the implementation of the proposed regulation and are expected to continue throughout the life of the affected sources. The major health effect associated with reducing PM 2.5 and PM 2.5 precursors (such
as SO 2 ) is a reduction in premature mortality. Other health173 effects associated with PM 2.5 emission reductions include avoiding cases of chronic bronchitis, heart attacks, asthma attacks, and work

- lost days (i.e., days when employees are unable to work). While we are unable to monetize the benefits associated with the HAP emissions reductions, we are able to monetize the benefits associated with the PM 2.5 and SO 2 emissions reductions. For SO 2 and PM 2.5 , we estimated the benefits associated with health effects of PM but were unable to quantify all categories of benefits (particularly those associated with ecosystem and visibility effects). Our estimates of the monetized benefits in 2013 associated with the implementation of the proposed alternative is range from $16 billion (2008 dollars)to $40 billion (2008 dollars) when using a 3 percent discount rate (or from $15 billion (2008 dollars)to $36 billion (2008 dollars) when using a 7 percent discount rate). This estimate, at a 3 percent discount rate, is about $11 billion (2008 dollars) to $35 billion (2008 dollars) higher than the estimated social costs shown earlier in this section. The general approach used to value benefits is discussed in more d etail earlier in this preamble. For more detailed information on the benefits estimated for the proposed rulemaking, refer to the RIA in the docket. 3. Future and Disproportionate Costs174 The Unfunded M andates Act requires that we estimate, where accurate estimation is reasonably feasible, future compliance costs imposed by the proposed rule and any disproportionate budgetary effects. Our estimates of the future compliance costs of the proposed rule are discussed previously in this preamble. We do not believe that there will be any disproportionate budgetary effects of the proposed rule on any particular areas of the country, State or local governments, types of communities (e.g., urban, rural), or part icular industry segments. See the results of the “Economic Impact Analysis of the Proposed Industrial Boilers and Process Heaters NESHAP,” the results of which are discussed previously in this preamble. 4. Effects on the National Econom y The Unfunded Mandates Act requires that we estimate the effect of the proposed rule on the national economy. To the extent feasible, we must estimate the effect on productivity, economic growth, full employment, creation of productive jobs, and interna tional competitiveness of the U.S. goods and services, if we determine that accurate estimates are reasonably feasible and that such effect is relevant and material. The nationwide economic impact of the proposed rule is presented in the “Economic Impact Analysis for the Industrial Boilers and Process Heaters MACT” in the docket. This analysis175 provides estimates of the effect of the proposed rule on some of the categories mentioned above. The results of the economic impact analysis are summarized previou sly in this preamble. The results show that there will be a small impact on prices and output, and little impact on communities that may be affected by the proposed rule. In addition, there should be little impact on energy markets (in this case, coal, n atural gas, petroleum products, and electricity). Hence, the potential impacts on the categories mentioned above should be small.
5. Consultation with Government Officials The Unfunded Mandates A ct requires that we describe the extent of the Agency’s prior consultation with affected State, local, and tribal officials, summarize the officials’ comments or concerns, and summarize our response to those comments or concerns. In addition, section 203 of the UMRA requires that we develop a plan for informing and advising small governments that may be significantly or uniquely impacted by a proposal. Although the proposed rule does not affect any State, local, or Tribal governments, we have consulted wi th State and local air pollution control officials. We also have held meetings on the proposed rule with many of the stakeholders from numerous individual companies, environmental groups, consultants and176 vendors, labor unions, and other interested parties . We have added materials to the Air Docket to document these meetings. In addition, we have determined that the proposed rule contains no regulatory requirements that might significantly or uniquely affect small governments. While some small government s may have some sources affected by the proposed rule, the impacts are not expected to be significant. Therefore, today's proposed rule is not subject to the requirements of section 203 of the

UMRA.
F. Regulatory Flexibility Act (RFA), as Amended by the S mall Business Regulatory Enforcement Fairness Act of 1996 (SBREFA), 5 U.S.C. 601 et seq. The RFA generally requires an agency to prepare a regulatory flexibility analysis of any rule subject to notice and comment rulemaking requirements under the Administ rative Procedure Act or any other statute unless the agency certifies that the rule will not have a significant economic impact on a substantial number of small entities. Small entities include small businesses, small organizations, and small governmental jurisdictions. For purposes of assessing the impacts of today’s proposed rule on small entities, small entity is defined as: (1) a small business according to Small Business Administration (SBA) size177 standards by the North American Industry Classificatio n System category of the owning entity. The range of small business size standards for the 40 affected industries ranges from 500 to 1,000 employees, except for petroleum refining and electric utilities. In these latter two industries, the size standard is 1,500 employees and a mass throughput of 75,000 barrels/day or less, and 4 million kilowatt

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

- for

- profit enterprise which is independently owned and operated and is not dominant in its field. Because an initial screening analysis for impact on small entities in dicated a likely significant impact for substantial numbers EPA convened a SBAR Panel to obtain advice and recommendation of representatives of the small entities that potentially would be subject to the requirements of this rule

. ( a ) Panel Process and Pan el Outreach As required by section 609(b) of the RFA, as amended by SBREFA, EPA also has conducted outreach to small entities and.
On January 22 , 200 9 EPA’s Small Business Advocacy Chairperson convened a Panel under section 609(b) of the RFA. In additio n178 to the Chair, the Panel consisted of the Director of the Sector Policies and Programs Division within EPA’s Office of Air and Radiation, the Chief Counsel for Advocacy of the Small Business Administration, and the Administrator of the Office of Informati on and Regulatory Affairs within the Office of Management and Budget. As part of the SBAR Panel process we conducted outreach with representatives from 14 various small entities that would be affected by this rule. The small entity representatives ( SERs ) included associations representing schools, churches, hotels/motels , wood product facilities and manufacturers of home furnishings. We met with these SERs to discuss the potential rulemaking approaches and potential options to decrease the impact of the rulemaking on their industries /sectors

. We distributed outreach materials to the SERs; these materials included background on the rulemaking, possible regulatory approaches, preliminary cost and economic impacts, and possible rulemaking alternatives. The Panel met with SERs from the industries that will be impacted directly by this rule on February 10 , 200 9 to discuss the outreach materials and receive feedback on the approaches and alternatives detailed in the outreach packet. (EPA also met with SERs on November 13 , 200 8 for an initial outreach meeting.) The Panel received written179 comments from the SERs following the meeting in response to discussions at the meeting and the questions posed to the SERs by the Agency. The SERs were specifically asked to provide comment on regulatory alternatives that could help to minimize the rule’s impact on small businesses. ( 1 ) Panel Recommendations for Small Business Flexibilities The Panel recommended that EPA consider and seek comment on a wide range of regulatory alternatives to mitigate the impacts of the rulemaking on small businesses, including those flexibility options described below. The following section summarizes the SBAR Panel recommendations. EPA has proposed provisions consistent with four of the Pan el’s recommendations

. Consistent with the RFA/SBREFA requirements, the Panel evaluated the assembled materials and small

- entity comments on issues related to elements of the IRFA. A copy of the Final Panel Report (including all comments received from SER s in response to the Panel’s outreach meeting as well as summaries of both outreach meetings that were held with the SERs is included in the docket for this proposed rule. A summary of the Panel recommendations is detailed below. As noted above, this

pro posal includes proposed provisions for all but one of the Panel recommendations. (a) Work Practice Standards180 The panel recommend ed that EPA consider requiring annual

tune

- ups, including standardized criteria outlining proper tune

up methods targeted at s maller boiler operators. The panel further recommend ed that EPA take comment on the efficacy of

energy a ssessments/a udits at improving combustion efficiency and the cost of performing the audits, especially to smaller boiler operators. A work practice sta ndard, instead of MACT emission limits, may be proposed if it can be justified under section 112(h) of the CAA, that is, it is impracticable to enforce the emission standards due to technical or economic limitations. W ork practice standards could reduce f uel use and improve combustion efficiency which would result in reduced emissions. In general, SERs commented that a regulatory approach to improve combustion efficiency, such as work practice standards, would have positive impacts with respect to the env ironment and energy use and save on compliance costs. The SERs were concerned with work practice standards that would require energy audits and implementation of audit findings. The basis of these concerns rested upon the uncertainty that there is no g uarantee that there are available funds to implement a particular audit’s findings. (b) Subcategorization181 The Panel recommended that EPA allow subcategorizations suggested by the SERs, unless EPA finds that a subcategorization is inconsistent with the Cl ean Air Act. SERs commented that subcategorization is a key concept that could ensure that like boilers are compared with similar boilers so that MACT floors are more reasonable and could be achieved by all units within a subcategory using appropriate em ission reduction strategies. SERs commented that EPA should subcategorize based on fuel type, boiler type, duty cycle, and location. (c) Health Based Compliance Alternatives (HBCA)

T he Panel recommend ed that EPA adopt the HBCA as a regulatory flexibil ity option for the Boiler MACT rulemaking. The panel recognize d , however, that EPA has concerns about its legal authority to provide an HBCA under the Clean Air Act, and EPA may ultimately determine that this flexibility is inconsistent with the Clean Air Act. SERs commented that adopting an HBCA would perhaps be the most important step EPA could take to mitigate the serious financial harm the Boiler MACT would otherwise inflict on small entities using solid fuels nationwide and, therefore, HBCA should be a critical component of any future rule to lessen impact on small entities.182 (d) Emissions Averaging The Panel recommend ed that EPA consider a provision for emission averaging and long averaging times for the proposed emission limits. SERs commented th at a measure EPA should consider to lessen the regulatory burden of complying with Boiler MACT is to allow emissions averaging at sources with multiple regulated units. SERs commented that another approach that can aide small entity compliance is to set l onger averaging times (i.e., 30

- days or more) rather than looking at a mere 3

- run (hour) average for performance. Given the inherent variability in boiler performance, an annual or quarterly averaging period for all HAP would prevent a single spike in emi ssions from throwing a unit into non

- compliance. (e) Compliance Costs The Panel recommend ed that EPA carefully weigh the potential burden of compliance requirements and consider for small entities options such as, emission averaging within facility, redu ced monitoring/testing requirements, or allowing more time for compliance. SERs noted that recordkeeping activities, as written in the vacated boiler MACT, would be especially challenging for small183 entities that do not have a dedicated environmental aff airs department.
G. Paperwork Reduction Act The information collection requirements in the proposed rule will be submitted for approval to the Office of Management and Budget under the Paperwork Reduction Act , 44 U.S.C. 3501 et
seq . An Information Col lection Request (ICR) document has been prepared by EPA (ICR No. 2028.01). The information requirements are based on notification, recordkeeping, and reporting requirements in the NESHAP General Provisions (40 CFR part 63, subpart A), which are mandat ory for all operators subject to national emission standards. These recordkeeping and reporting requirements are specifically authorized by section 114 of the CAA (42 U.S.C. 7414). All information submitted to EPA pursuant to the recordkeeping and report ing requirements for which a claim of confidentiality is made is safeguarded according to Agency policies set forth in 40 CFR part 2, subpart B. The proposed rule would require maintenance inspections of the control devices but would not require any notif ications or reports beyond those required by the General Provisions. The recordkeeping requirements require only the specific information needed to determine compliance.184 The annual monitoring, reporting, and recordkeeping burden for this collection (a veraged over the first 3 years after the effective date of the standards) is estimated to be $109 million. This includes 364,942 labor hours per year at a total labor cost of $34.5 million per year, and total non

- labor capital costs of $74.5 million per y ear. This estimate includes initial and annual performance test, conducting an documenting an energy audit, conducting and documenting a tune

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

- up and energy audit costs and cost were also included in the cost estimates presented in the control costs impacts estimates in section IV.D of this preamble. The total burden for the Federal government (averaged over the first 3 years after the effective date of the standard) is estimated to be 121,506 hours per year at a total labor cost of $6.4 million per year. Burden means the total time, effort, or financial resources expended by persons to generate, mainta in, retain, or disclose or provide information to or for a Federal agency. This includes the time needed to review instructions; develop, acquire, install, and utilize technology and systems for the purposes of collecting, validating, and verifying inform ation,185 processing and maintaining information, and disclosing and providing information; adjust the existing ways to comply with any previously applicable instructions and requirements; train personnel to be able to respond to a collection of information; search data sources; complete and review the collection of information; and transmit or otherwise disclose the information. An Agency may not conduct or sponsor, and a person is not required to respond to, a collection of information unless it displays a currently valid OMB control number. The OMB control numbers for our regulations are listed in 40 CFR part 9 and 48 CFR chapter 15. To comment on EPA’s need for this information, the accuracy of the provided burden estimates, and any suggested methods for minimizing respondent burden, including the use of automated collection techniques, EPA has established a public docket for this action, which includes this ICR, under Docket ID number

EPA

- HQ

- OAR

- 2002

- 0058 . Submit any comments related to the ICR to

EP A and OMB. See ADDRESSES section at the beginning of this preamble for where to submit comments to EPA. Send comments to OMB at the Office of Information and Regulatory Affairs, Office of Management and Budget, 725 17th Street, NW, Washington, DC 20503, Attention: Desk Office for EPA. Since OMB is required to make a decision concerning the ICR between 30 and 60 days186 after [INSERT DATE OF PUBLICATION IN THE FEDERAL REGISTER], a comment to OMB is best assured of having its full effect if OMB receives it b y [INSERT DATE 30 DAYS FROM DATE OF PUBLICATION IN THE FEDERAL REGISTER]. The final rule will respond to any OMB or public comments on the information collection requirements contained in this proposal.

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

- 113; 15 U.S.C. 272 note) directs the EPA to use voluntary consensus standards in their regulatory and procurement activities unless to do so would b e inconsistent with applicable law or otherwise impractical. Voluntary consensus standards are technical standards (e.g., materials specifications, test methods, sampling procedures, business practices) developed or adopted by one or more voluntary consen sus bodies. The NTTAA directs EPA to provide Congress, through annual reports to the Office of Management and Budget, with explanations when an agency does not use available and applicable voluntary consensus standards. This rulemaking involves technica l standards. The EPA cites the following standards in the proposed rule: EPA Methods 1, 2, 2F, 2G, 3A, 3B, 4, 5, 5D, 17, 19, 26, 26A, 29 of 40 CFR part 60. Consistent with the NTTAA, EPA conducted searches to187 identify voluntary consensus standards in add ition to these EPA methods. No applicable voluntary consensus standards were identified for EPA Methods 2F, 2G, 5D, and 19. The search and review results have been documented and are placed in the docket for the proposed rule. The three voluntary cons ensus standards described below were identified as acceptable alternatives to EPA test methods for the purposes of the proposed rule. The voluntary consensus standard ASME PTC 19

- 10

- 1981

- Part 10, “Flue and Exhaust Gas Analyses,” is cited in the proposed rule for its manual method for measuring the oxygen, carbon dioxide, and carbon monoxide content of exhaust gas. This part of ASME PTC 19

- 10

- 1981

- Part 10 is an acceptable alternative to Method 3B. The voluntary consensus standard ASTM D6522

- 00, “Standard Test Method for the Determination of Nitrogen Oxides, Carbon Monoxide, and Oxygen Concentrations in Emissions from Natural
Gas

- Fired Reciprocating Engines, Combustion Turbines, Boilers and Process Heaters Using Portable Analyzers” is an acceptable alterna tive to EPA Method 3A for identifying carbon monoxide and oxygen concentrations for the proposed rule when the fuel is natural gas.188 The voluntary consensus standard ASTM Z65907, “Standard Method for Both Speciated and Elemental Mercury Determination,” is an acceptable alternative to EPA Method 29 (portion for mercury only) for the purpose of the proposed rule. This standard can be used in the proposed rule to determine the mercury concentration in stack gases for boilers with rated heat input capacities of greater than 250 MMBtu per hour. In addition to the voluntary consensus standards EPA uses in the proposed rule, the search for emissions measurement procedures identified 15 other voluntary consensus standards. The EPA determined that 13 of these 15 standards identified for measuring emissions of the HAP or surrogates subject to emission standards in the proposed rule were impractical alternatives to EPA test methods for the purposes of the rule. Therefore, EPA does not intend to adopt these standard s for this purpose. The reasons for this determination for the 13 methods are discussed below. The voluntary consensus standard ASTM D3154

- 00, “Standard Method for Average Velocity in a Duct (Pitot Tube Method),” is impractical as an alternative to EPA M ethods 1, 2, 3B, and 4 for the purposes of the proposed rulemaking since the standard appears to lack in quality control and quality assurance requirements. Specifically, ASTM D3154

- 00 does not include the189 following: (1) proof that openings of standard pi tot tube have not plugged during the test; (2) if differential pressure gauges other than inclined manometers ( e.g. , magnehelic gauges) are used, their calibration must be checked after each test series; and (3) the frequency and validity range for calibra tion of the temperature sensors. The voluntary consensus standard ASTM D3464

- 96 (2001), “Standard Test Method Average Velocity in a Duct Using a Thermal Anemometer,” is impractical as an alternative to EPA Method 2 for the purposes of the proposed rule pr imarily because applicability specifications are not clearly defined, e.g., range of gas composition, temperature limits. Also, the lack of supporting quality assurance data for the calibration procedures and specifications, and certain variability issues that are not adequately addressed by the standard limit EPA’s ability to make a definitive comparison of the method in these areas. The voluntary consensus standard ISO 10780:1994, “Stationary Source Emissions

– Measurement of Velocity and Volume Flowrate of Gas Streams in Ducts,” is impractical as an alternative to EPA Method 2 in the proposed rule. The standard recommends the use of an L

- shaped pitot, which historically has not been recommended by EPA. The EPA specifies the S

- type190 design which has large openings that are less likely to plug up with dust. The voluntary consensus standard, CAN/CSA Z223.2

- M86(1999), “Method for the Continuous Measurement of Oxygen, Carbon Dioxide, Carbon Monoxide, Sulphur Dioxide, and Oxides of Nitrogen in Enclosed Combust ion Flue Gas Streams,” is unacceptable as a substitute for EPA Method 3A since it does not include quantitative specifications for measurement system performance, most notably the calibration procedures and instrument performance characteristics. The inst rument performance characteristics that are provided are nonmandatory and also do not provide the same level of quality assurance as the EPA methods. For example, the zero and span/calibration drift is only checked weekly, whereas the EPA methods requires drift checks after each run. Two very similar voluntary consensus standards, ASTM D5835

- 95 (2001), “Standard Practice for Sampling Stationary Source Emissions for Automated Determination of Gas Concentration,” and
ISO 10396:1993, “Stationary Source Emiss ions: Sampling for the Automated Determination of Gas Concentrations,” are impractical alternatives to EPA Method 3A for the purposes of the proposed rule because they lack in detail and quality assurance/quality control requirements. Specifically, these two standards do not191 include the following: (1) sensitivity of the method; (2) acceptable levels of analyzer calibration error; (3) acceptable levels of sampling system bias; (4) zero drift and calibration drift limits, time span, and required testing fre quency; (5) a method to test the interference response of the analyzer; (6) procedures to determine the minimum sampling time per run and minimum measurement time; and (7) specifications for data recorders, in terms of resolution (all types) and recording intervals (digital and analog recorders, only). The voluntary consensus standard ISO 12039:2001, “Stationary Source Emissions

-- Determination of Carbon Monoxide, Carbon Dioxide, and Oxygen

-- Automated Methods,” is not acceptable as an alternative to EPA Met hod 3A. This ISO standard is similar to EPA Method 3A, but is missing some key features. In terms of sampling, the hardware required by
ISO 12039:2001 does not include a 3

- way calibration valve assembly or equivalent to block the sample gas flow while

ca libration gases are introduced. In its calibration procedures, ISO 12039:2001 only specifies a two

- point calibration while EPA Method 3A specifies a three

- point calibration. Also, ISO 12039:2001 does not specify performance criteria for calibration error , calibration drift, or sampling192 system bias tests as in the EPA method, although checks of these quality control features are required by the ISO standard. The voluntary consensus standard ASME PTC

- 38

- 80 R85 (1985), “Determination of the Concentration o f Particulate Matter in Gas Streams,” is not acceptable as an alternative for EPA Method 5 because ASTM PTC

- 38

- 80 is not specific about equipment requirements, and instead presents the options available and the pro’s and con’s of each option. The key spec ific differences between ASME PTC

- 38

- 80 and the EPA methods are that the ASME standard: (1) allows in

- stack filter placement as compared to the out

- of

- stack filter placement in EPA Methods 5 and 17; (2) allows many different types of nozzles, pitots, and filtering equipment; (3) does not specify a filter weighing protocol or a minimum allowable filter weight fluctuation as in the EPA methods; and (4) allows filter paper to be only 99 percent efficient, as compared to the 99.95 percent efficiency required b y the EPA methods. The voluntary consensus standard ASTM D3685/D3685M

- 98, “Test Methods for Sampling and Determination of Particulate Matter in Stack Gases,” is similar to EPA Methods 5 and 17, but is lacking in the following areas that are needed to pro duce quality, representative particulate data: (1) requirement that the filter holder temperature should be between 120 o C and 134 o C,193 and not just “above the acid dew

- point;” (2) detailed specifications for measuring and monitoring the filter holder tempera ture during sampling; (3) procedures similar to EPA Methods 1, 2, 3, and 4, that are required by EPA Method 5; (4) technical guidance for performing the Method 5 sampling procedures, e.g., maintaining and monitoring sampling train operating temperatures, s pecific leak check guidelines and procedures, and use of reagent blanks for determining and subtracting background contamination; and (5) detailed equipment and/or operational requirements, e.g., component exchange leak checks, use of glass cyclones for he avy particulate loading and/or water droplets, operating under a negative stack pressure, exchanging particulate loaded filters, sampling preparation and implementation guidance, sample recovery guidance, data reduction guidance, and particulate sample cal culations input. The voluntary consensus standard ISO 9096:1992, “Determination of Concentration and Mass Flow Rate of Particulate Matter in Gas Carrying Ducts

- Manual Gravimetric Method,” is not acceptable as an alternative for EPA Method 5. Although s ections of ISO 9096 incorporate EPA Methods 1, 2, and 5 to some degree, this ISO standard is not equivalent to EPA Method 5 for collection of particulate matter. The standard ISO194 9096 does not provide applicable technical guidance for performing many of t he integral procedures specified in Methods 1, 2, and 5. Major performance and operational details are lacking or nonexistent, and detailed quality assurance/quality control guidance for the sampling operations required to produce quality, representative particulate data (e.g., guidance for maintaining and monitoring train operating temperatures, specific leak check guidelines and procedures, and sample preparation and recovery procedures) are not provided by the standard, as in EPA Method 5. Also, detail s of equipment and/or operational requirements, such as those specified in EPA Method 5, are not included in the ISO standard, e.g., stack gas moisture measurements, data reduction guidance, and particulate sample calculations. The voluntary consensus st andard CAN/CSA Z223.1

- M1977, “Method for the Determination of Particulate Mass Flows in Enclosed Gas Streams,” is not acceptable as an alternative for EPA Method 5. Detailed technical procedures and quality control measures that are required in EPA Method s 1, 2, 3, and 4 are not included in CAN/CSA Z223.1. Second, CAN/CSA Z223.1 does not include the EPA Method 5 filter weighing requirement to repeat weighing every 6 hours until a constant weight is achieved. Third, EPA Method 5 requires the filter weight to be reported to195 the nearest 0.1 mg, while CAN/CSA Z223.1 requires only to the nearest 0.5 mg. Also, CAN/CSA Z223.1 allows the use of a standard pitot for velocity measurement when plugging of the tube opening is not expected to be a problem. Whereas, EPA Method 5 requires an S

- shaped pitot. The voluntary consensus standard EN 1911

- 1,2,3 (1998), “Stationary Source Emissions

- Manual Method of Determination of HCl

- Part 1: Sampling of Gases Ratified European Text

- Part 2: Gaseous Compounds Absorption Rat ified European Text

- Part 3: Adsorption Solutions Analysis and Calculation Ratified European Text,” is impractical as an alternative to EPA Methods 26 and 26A. Part 3 of this standard cannot be considered equivalent to EPA Method 26 or 26A because the sam ple absorbing solution (water) would be expected to capture both HCl and chlorine gas, if present, without the ability to distinguish between the two. The EPA Methods 26 and 26A use an acidified absorbing solution to first separate HCl and chlorine gas so that they can be selectively absorbed, analyzed, and reported separately. In addition, in EN 1911 the absorption efficiency for chlorine gas would be expected to vary as the pH of the water changed during sampling. The voluntary consensus standard EN 13 211 (1998), is not acceptable as an alternative to the mercury portion of EPA196 Method 29 primarily because it is not validated for use with impingers, as in the EPA method, although the method describes procedures for the use of impingers. This European st andard is validated for the use of fritted bubblers only and requires the use of a side (split) stream arrangement for isokinetic sampling because of the low sampling rate of the bubblers (up to 3 liters per minute, maximum). Also, only two bubblers (or i mpingers) are required by EN 13211, whereas EPA Method 29 require the use of six impingers. In addition, EN 13211 does not include many of the quality control procedures of EPA Method 29, especially for the use and calibration of temperature sensors and

c ontrollers, sampling train assembly and disassembly, and filter weighing. Two of the 15 voluntary consensus standards identified in this search were not available at the time the review was conducted for the purposes of the proposed rule because they are under development by a voluntary consensus body: ASME/BSR MFC 13M, “Flow Measurement by Velocity Traverse,” for EPA Method 2 (and possibly 1); and ASME/BSR MFC 12M, “Flow in Closed Conduits Using Multiport Averaging Pitot Primary Flowmeters,” for EPA

Met hod 2. Section 63.7520 and Tables 4A through 4D to subpart DDDDD, 40 CFR part 63, list the EPA testing methods included in the197

proposed rule. Under §63.7(f) and §63.8(f) of subpart A of the General Provisions, a source may apply to EPA for permission to use alternative test methods or alternative monitoring requirements in place of any of the EPA testing methods, performance specifications, or procedures.

I. Executive Order 13211, Actions Concerning Regulations That Significantly Affect Energy Supply, D istribution, or Use Executive Order 13211, (66 FR 28355, May 22, 2001), provides that agencies shall prepare and submit to the Administrator of the Office of Information and Regulatory Affairs, Office of Management and Budget, a Statement of Energy Effect s for certain actions identified as significant energy actions. Section 4(b) of Executive Order 13211 defines “significant energy actions” as “any action by an agency (normally published in the Federal Register ) that promulgates or is expected to lead to the promulgation of a final rule or regulation, including notices of inquiry, advance notices of proposed rulemaking, and notices of proposed rulemaking: (1)(i) that is a significant regulatory action under Executive Order 12866 or any successor order, and (ii) is likely to have a significant adverse effect on the supply, distribution, or use of energy; or (2) that is designated by the Administrator of the Office of Information and Regulatory Affairs as a significant energy action.” The proposed rule is no t a “significant198

regulatory action” because it is not likely to have a significant adverse effect on the supply, distribution, or use of energy. The basis for the determination is as follows. We estimate a 0. 14 % price increase for the energy sector and a 0.0 7 % percentage change in production. We estimate a 0. 18 % increase in energy imports. For more information on the estimated energy effects, please refer to the economic impact analysis for the proposed rule. The analysis is available in the public doc ket. Therefore, we conclude that the proposed rule when implemented is not likely to have a significant adverse effect on the supply, distribution, or use of energy.

J. Executive Order 12898: Federal Actions to Address Environmental Justice in Minor ity Populations and Low

- Income Populations Executive Order 12898 (59 FR 7629, February 16, 1994) establishes Federal executive policy on environmental justice (EJ). Its main provision directs Federal agencies, to the greatest extent practicable and permi tted 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, l ow - income, and Tribal populations in the United States.1 99

This proposed action establishes national emission standards for new and existing industrial, commercial, institutional boilers and process heaters that combust non

- waste materials (i.e. natural gas, process gas, fuel oil, biomass, and coal) and that are located at a major source. The EPA estimates that there are approximately 38,000 units covered by this rule. The proposed rule will reduce emissions of all the listed HAP that come from boilers and process heaters. This includes metals (mercury, arsenic, beryllium, cadmium, chromium, lead, manganese, nickel, and selenium), organics (POM, acetaldehyde, acrolein, benzene, dioxins, ethylene dichloride, formaldehyde, and PCB), hydrochloric acid, hydrofl uoric acid (S ee T able 6 of this preamble ). Adverse health effects from these pollutants include cancer and chronic health disorders (e.g., irritation of the lung, skin, and mucus membranes, effects on the central nervous system, and damage to the kidneys) , and acute health disorders (e.g., lung irritation and congestion, alimentary effects such as nausea and vomiting, and effects on the kidney and central nervous system). The rule will also result in substantial reductions of criteria pollutants (i.e. CO, PM, SO 2 ) and ozone precursors. EPA reviewed the distributions of baseline exposures to and risks from all HAP from all sources among different socio

demographic groups for this rule, and related the locations of200

expected emission reductions from this rul e to the locations of higher than average cancer risks due to HAP, as estimated via EPA’s 2002 National Air Toxics Assessment (NATA). The review identified those census blocks within 3 miles of affected sources and determined the demographic composition ( e.g. race, income, education, etc) of these census blocks. Based on the fact that the rule does not allow emission increases, the EPA has determined that the proposed rule will not have disproportionately high and adverse human health or environmental e ffects on minority, low

- income, or Tribal populations. Also, based on the review of NATA results, estimated emission reductions associated with this rule, and the demographics within 3 miles of each boiler, EPA has determined that the greatest emission re ductions tend to occur in the areas of higher total cancer risks from HAPs. These areas tend to have lower proportions of Whites and American Indians, higher proportions of African

- Americans, Hispanics, and “Other and Multi

- racial” populations, and higher proportions of families with incomes below the poverty level. However, to the extent that any minority, low income, or Tribal subpopulation is disproportionately impacted by the current emissions as a result of the proximity of their homes to these sourc es, that subpopulation also stands to see increased environmental and201

health benefit from the emissions reductions called for by this rule. EPA defines “Environmental Justice” to include meaningful involvement of all people regardless of race, color, nati onal origin, or income with respect to the development, implementation, and enforcement of environmental laws, regulations, and polices. To promote meaningful involvement, EPA has developed a communication and outreach strategy to ensure that interested c ommunities have access to this proposed rule, are aware of its content, and have an opportunity to comment during the comment period. During the comment period, EPA will publicize the rulemaking via EJ newsletters, Tribal newsletters, EJ listserves, and t he internet, including the Office of Policy, Economics, and Innovation’s (OPEI) Rulemaking Gateway web site (http://yosemite.epa.gov/opei/rulegate.nsf/content/index.html?op endocument). EPA will also provide general rulemaking fact sheets (e.g., why is thi s important for my community) for EJ community groups and conduct conference calls and Webinars with interested communities. In addition, state and federal permitting requirements will provide state, local governments, and communities an opportunity to pr ovide their comments on the permit conditions associated with permitting the sources affected by this rulemaking.202203

List of Subjects in 40 CFR part 63 Environmental protection, Administrative practice and procedure, Air pollution control, Hazardous substances, Intergovernmental relations, Reporting and recordkeeping requirements.

______________________ Dated:

_______________________ Lisa P. Jackson , Administrator.204

For the reasons stated in the preamble, title 40, chapter I, part 63 of the Code of the Federal Regulations is proposed to be amended as follows: **PART 63 --**  **[AMENDED]** 1. The authority citation for part 63 continues to read as follows: **Authority** : 42 U.S.C. 7401, et seq
. 2. Part 63 is amended by adding subpart DDDDD to read as foll ows: **Subpart DDDDD --**  **National Emission Standards for Hazardous Air Pollutants for Industrial, Commercial, and**  **Institutional Boilers and Process Heaters**
Sec. **What this Subpart Covers** 63.7480 What is the purpose of this subpart? 63.7485 Am I subject to th is subpart? 63.7490 What parts is the affected source of my facility does t his subpart cover? ? 63.7491 Are any boilers or process heaters not subject to this subpart? 63.7495 When do I have to comply with this subpart? **Emission Limitations and Work Pr actice Standards**  63.7499 What are the subcategories of boilers and process heaters? 63.7500 What emission limitations and , work practice standards , and operating limits must I meet? **General Compliance Requirements** Formatted: Indent: Left: 0", Hanging: 1", Tab stops: Not at 0"205 63.7505 What are my general requirement s for complying with this subpart? **Testing , Fuel Analyses,**  **and Initial Compliance Requirements** 63.7510 By W hat are my initial compliance requirements and by what date must I conduct performance tests or other initial compliance demonstrations them ? 63.7515 When must I conduct subsequent performance tests or fuel analyses ? 63.7520 What performance stack tests , design evaluations, and other procedures must I use for the performance tests ? 63.7521 What fuel analyses and procedures must I use for the performance tests ? 63.7522 Can I use emission averaging to comply with this subpart? 63.7525 What are my monitoring, installation, operation, and maintenance requirements? 63.7530 How do I demonstrate initial compliance with the emission limitations and work practic e standards? **Continuous Compliance Requirements** 63.7535 How do I monitor and collect data to demonstrate continuous compliance? 63.7540 How do I demonstrate continuous compliance with the emission limitations and work practice standards? 63.7541 How do I demonstrate continuous compliance under the emission averaging provision? **Notifications, Reports, and Records** 63.7545 What notifications must I submit and when? 63.7550 What reports must I submit and when? 63.7555 What records must I keep? 63.7560 In wh at form and how long must I keep my records? **Other Requirements and Information** 63.7565 What parts of the General Provisions apply to me? 63.7570 Who implements and enforces this subpart? 63.7575 What definitions apply to this subpart? **Tables to Subpart DDDDD of Part 63** 206 Table 1 to Subpart DDDDD of Part 63

-- - Emission Limits for New or Reconstructed Boilers and Process Heaters Table 2 .A to Subpart DDDDD of Part 63

-- Operating

– Emission Limits for Existing Boilers and Process Heaters in the Large, Limi ted Use, or Small Solid Fuel Subcategories (Units with heat input capacity of 10 million Btu per hour or greater) Table 2.B to Subpart DDDDD of Part 63

-- Operating Limits for Boilers and Process Heaters in the Large, Limited Use, or Small Liquid Fuel Subcat egories Table 3 to Subpart DDDDD of Part 63

-- - Work Practice Standards Table 4 .A to Subpart DDDDD of Part 63

-- Requirements

– Operating Limits for Performance Tests for Particulate Matter Emissions or Total Selected Metals Emissions from Boilers or and Proc ess Heaters in Large, Limited Use, or Small Solid Fuel Subcategories Table 4.B 5 to Subpart DDDDD of Part 63

-- - Performance Test ing Requirements for Performance Tests for Particulate Matter Emissions from Boilers or Process Heaters in Large, Limited Use, o r Small Liquid Fuel Subcategories Table 4.C to Subpart DDDDD of Part 63

-- Requirements for Performance Tests for Hydrogen Chloride Emissions from Boilers or Process Heaters in Large, Limited Use, or Small Solid Fuel Subcategories Table 4.D to Subpart DDDDD of Part 63

-- Requirements for Performance Tests for Hydrogen Chloride Emissions from Boilers or Process Heaters in Large, Limited Use, or Small Liquid Fuel Subcategories Table 4.E to Subpart DDDDD of Part 63

-- Requirements for Performance Tests for Mercury Emissions from Boilers or Process Heaters in Large, Limited Use, or Small Solid Fuel Subcategories Table 5.A to Subpart DDDDD of Part 63

-- Initial Compliance With Emission Limitations for Particulate Matter or Total Selected Metals for Boilers or Process He aters in Large, Limited Use, or Small Solid Fuel Subcategories Table 5.B to Subpart DDDDD of Part 63

-- Initial Compliance With Emission Limitations for Particulate Matter for Boilers or Process Heaters in Large, Limited Use, or Small Liquid Fuel Subcategori es Table 5.C to Subpart DDDDD of Part 63

-- Initial Compliance With Emission Limitations for Hydrogen Chloride for Boilers or Process Heaters in Large, Limited Use, or Small Solid Fuel Subcategories Formatted: Indent: Left: 0", Hanging: 0.5", Tab stops: Not at 0"

Formatted: Indent: Left: 0", Hanging: 0.5", Tab stops: Not at 0"207 Table 5.D to Subpart DDDDD of Part 63

-- Initial Compliance W ith Emission Limitations for Hydrogen Chloride for Boilers or Process Heaters in Large, Limited Use, or Small Liquid Fuel Subcategories Table 5.E to Subpart DDDDD of Part 63

-- Initial Compliance With Emission Limitations for Mercury for Boilers or Process H eaters in Large, Limited Use, or Small Solid Fuel, Subcategories Table 6 to Subpart DDDDD of Part 63

-- Initial Compliance with Work Practice Standards

– Fuel Analysis Requirements Table 7 .A to Subpart DDDDD of Part 63

-- Continuous Compliance with Emission L imitations for Boilers or Process Heaters in Large, Limited Use, or Small Solid Fuel Subcategories

– Establishing Operating Limits Table 7.B to Subpart DDDDD of Part 63

-- Continuous Compliance with Emission Limitations for Boilers or Process Heaters in Larg e, Limited Use, or Small Liquid Fuel Subcategories Table 8 to Subpart DDDDD of Part 63

-- – Demonstrating Continuous Compliance with Work Practice Standards Table 9 to Subpart DDDDD of Part 63

-- – Reporting Requirements for Reports Table 10 to Subpart DDDDD of Part 63

-- - Applicability of General Provisions to Subpart DDDDD
**WHAT THIS SUBPART COVERS** §63.7480 What is the purpose of this subpart? This subpart establishes national emission limitatio ns and work practice standards for hazardous air pollutants (HAP) emitted from industrial, commercial, and institutional boilers and process heaters. This subpart also establishes requirements to demonstrate initial and continuous compliance with the emis sion limitations and work practice standards. §63.7485 Am I subject to this subpart?208 You are subject to this subpart if you own or operate an industrial, commercial, or institutional boiler or

process heater as defined in §63.7575 that is located at, or is part of, a major source of HAP as defined in §63.2 or §63.761 (40 CFR part 63, subpart HH, National Emission Standards for Hazardous Air Pollutants from Oil and Natural Gas Production Facilities) , exc ept as specifi ed in §63.749 1

. § 63.7490 What is the affected source of this subpart? (a) This subpart applies to new, reconstructed, or and existing affected sources as described in paragraphs (a)(1) and (2) of this section. (1) The affected source of th is subpart is the collection of all existing industrial, commercial, and institutional boilers and process heaters within a subcategory located at a major source as defined in §63.7575. (2) The affected source of this subpart is each new or reconstructed i ndustrial, commercial, or institutional boiler or process heater located at a major source as defined in §63.7575. (b) A boiler or process heater is new if you commence construction of the boiler or process heater after [ INSERT
DATE OF PUBLICATION OF THIS PROPOSED RULE IN THE FEDERAL209 REGISTER ] , and you meet the applicability criteria at the time you commence construction. (c) A boiler or process heater is reconstructed if you meet the reconstruction criteria as defined in §63.2, you commence reconstruction after [ INSERT DATE OF PUBLICATION
OF THIS PROPOSED RULE IN THE FEDERAL REGISTER ] , and you meet the applicability criteria at the time you commence reconstruction. (d) A boiler or process heater is existing if it is not new or reconstructed.
§ 63.7491 Are any boilers or process heaters not subject to this subpart? The types of boilers and process heaters listed in paragraphs (a) through (o) of this section are not subject to this subpart. (a) A municipal waste combustor covered by 40 CFR part 60, subpart A AAA, subpart BBBB, subpart Cb or subpart Eb. (b) A hospital/medical/infectious waste incinerator covered by 40 CFR part 60, subpart Ce or subpart Ec. (c (a ) An electric utility steam generating uni t
. (d) A boiler or process heater required to have a permit under section 3005 of the Solid Waste Disposal Act or covered by 40 CFR part 63, subpart EEE ( e.g. , hazardous waste boilers).210 (e) A commercial and industrial solid waste incineration unit covered by 40 CFR part 60, subpart CCCC or subpart

DDDD. (f ( b ) A rec overy boiler or furnace covered by 40 CFR part 63, subpart MM. ( g c ) A boiler or process heater that is used specifically for research and development. This does not include units that provide heat or steam to a process at a research and development facilit y. ( h d ) A hot water heater as defined in this subpart. ( i e ) A refining kettle covered by 40 CFR part 63, subpart

X. ( j f ) An ethylene cracking furnace covered by 40 CFR part 63, subpart YY. ( k g ) Blast furnace stoves as described in the EPA document, entitle d “National Emission Standards for Hazardous Air Pollutants (NESHAP) for Integrated Iron and Steel Plants

— Background Information for Proposed Standards,” (EPA

– 453/R

– 01

– 005). ( l i ) Any boiler or process heater specifically listed as an affected source in ano ther standard(s) under 40 CFR part 63.211 ( m) Any boiler or process heater specifically listed as an affected source in another standard(s) established under section 129 of the Clean Air Act (CAA). (n j ) Temporary boilers as defined in this subpart. ( o k ) Blast furnace gas fuel

- fired boilers and process heaters as defined in this subpart. §63.7495 When do I have to comply with this subpart? (a) If you have a new or reconstructed boiler or proces s heater, you must comply with this subpart by [DATE THE FINAL RULE IS PUBLISHED IN THE FEDERAL REGISTER] or upon startup of your boiler or process heater, whichever is later. (b) If you have an existing boiler or process heater, you must comply with this subpart no later than [3 YEARS AFTER

DATE THE FINAL RULE IS PUBLISHED IN THE FEDERAL REGISTER ]

. (c) If you have an area source that increases its emissions or its potential to emit such that it becomes a major source of HAP, paragraphs (c)(1) and (2) of th is section apply to you. (1) Any new or reconstructed boiler or process heater at the existing source must be in compliance with this subpart upon startup.212 (2) Any existing boiler or process heater at the existing

source must be in compliance with this sub part within 3 years after the source becomes a major source. (d) You must meet the notification requirements in §63.7545 according to the schedule in §63.7545 and in subpart A of this part. Some of the notifications must be submitted before you are require d to comply with the emission limits and work practice standards in this subpart.
**EMISSION LIMITATIONS AND WORK PRACTICE STANDARDS** § 63.7499 What are the subcategories of boilers and process heaters? The subcategories of boilers and process heaters are : (1) Pulverized coal units , (2) Stokers designed to burn coal, (3) Fluidized bed units designed to burn coal, (4) Stokers designed to burn biomass, (5) Fluidized bed units designed to burn biomass, (6) Suspension burners/Dutch Ovens designed to burn biomass, (7) Fuel Cells design ed to burn biomass, (8) U nits designed to burn liquid fuel, (9) Units designed to burn natural gas/refinery gas, and (10) Units designed to burn other gases. Each subcategory is defined in §63.7575.213 § 63.7500 What emission limits, work practice standards, and opera ting limits must I meet? (a) You must meet the requirements in paragraphs (a)(1) and (2) of this section. You must meet these requirements at all times. (1) You must meet each emission limit and work practice standard in Table 1 through 3 to this subpar t that applies to your boiler or process heater, for each boiler or process heater at your source, except as provided under §63.75 22

. (2) You must meet each operating limit in Table 4 to this subpart that applies to your boiler or process heater. If you u se a control device or combination of control devices not covered in Table 4 to this subpart, or you wish to establish and monitor an alternative operating limit and alternative monitoring parameters, you must apply to the United States Environmental Prote ction Agency (EPA) Administrator for approval of alternative monitoring under §63.8(f). (b) As provided in §63.6(g), EPA may approve use of an alternative to the work practice standards in this section. **GENERAL COMPLIANCE REQUIREMENTS** §63.7505 What are my general requirements for complying with this subpart?214 (a) You must be in compliance with the emission limits and operating limits in this subpart that . These limits apply to you at all times. ( b ) At all times you must operate and maintain any affe cted source, including associated air pollution control equipment and monitoring equipment, in a manner consistent with safety and good air pollution control practices for minimizing emissions. The general duty to minimize emissions does not require you t o make any further efforts to reduce emissions if levels required by this standard have been achieved. Determination of whether such operation and maintenance procedures are being used will be based on information available to the Administrator which

may include, but is not limited to, monitoring results, review of operation and maintenance procedures, review of operation and maintenance records, and inspection of the

source. (c) You can demonstrate compliance with the applicable emission limit for HCl or mercury using fuel analysis if the emission rate calculated according to §63.7530(d) is less than the applicable emission limit. Otherwise, you must demonstrate compliance for HCl or mercury using performance stack testing. You must demonstrate complianc e with all other applicable limits using performance stack215 testing, or the continuous monitoring system (CMS) where applicable. (d) If you demonstrate compliance with any ap plicable emission limit through performance stack testing, you must develop a site

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

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

- specific monitoring plan , if requested, at least 60 days before your initial performance evaluation of your
CMS. (i) Installation of the CMS sampling probe or other interface at a measurement location relative to each affected process unit such tha t the measurement is representative of control of the exhaust emissions ( e.g. , on or downstream of the last control device); (ii) Performance and equipment specifications for the sample interface, the pollutant concentration or parametric216 signal analyzer, and the data collection and reduction systems; and (iii) Performance evaluation procedures and acceptance criteria ( e.g. , calibrations). (2) In your site

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

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

- specific monitoring plan.
**TESTING , FUEL ANALYSES,**  **AND INITIAL COMPLIANCE REQUIREMENTS**
§ 63.7510 What are my initial compliance requirements and by what date must I conduct them?217 (a) For affected sources that elect to demonstrate compliance with any of the emission limits of this subpart through performance stack testing, your initial compliance requirements include conducting performance stack tests according to §63.7520 an d Table 5 to this subpart, conducting a fuel analysis for each type of fuel burned in your boiler or process heater according to §63.7521 and Table 6 to this subpart, establishing operating limits according to §63.7530 and Table 7 to this subpart, and cond ucting CMS performance evaluations according to §63.7525. For affected sources that burn a single type of fuel, you are exempted from the initial compliance requirements of conducting a fuel analysis for each type of fuel burned in your boiler or process heater according to §63.7521 and Table 6 to this subpart. (b) For affected sources that elect to demonstrate compliance with the emission limits for HCl or mercury through fuel analysis, your initial compliance requirement is to conduct a fuel analysis fo r each type of fuel burned in your boiler or process heater according to §63.7521 and Table 6 to this subpart and establish operating limits according to §63.7530 and Table 8 to this subpart. (c) If your boiler or process heater has a heat input capacity less than 100 MMBtu per hour, your initial218 compliance demonstration is conducting a performance stack test for CO according to Table 5 to this subpart. If your boiler or process heater has a heat input capacity of 100 MMBtu per hour or greater, your initi al compliance demonstration is conducting a performance evaluation of your continuous emission monitoring system for CO according to §63.7525(a). (d ( d ) If your boiler or process heater has a heat input capacity of 25 0 MMBtu per hour or greater and combus t coal, biomass, or residual oil , your initial compliance demonstration is conducting a performance evaluation of your continuous emission monitoring system for PM according to §63.7525( b ). ( e ) For existing affected sources, you must demonstrate initial c ompliance no later than 180 days after the compliance date that is specified for your source in §63.7495 and according to the applicable provisions in §63.7(a)(2) as cited in Table 10 to this subpart. ( e f ) If your new or reconstructed affected source

comm enced construction or reconstruction between [INSERT
DATE OF PUBLICATION OF THIS PROPOSED RULE IN THE FEDERAL REGISTER] and [INSERT DATE 60 DAYS AFTER PUBLICATION OF THE FINAL RULE IN THE FEDERAL REGISTER] , you must demonstrate initial compliance with eith er the proposed emission li mits219 or the promulgated emission limits no later than 180 days after [INSERT DATE 60 DAYS AFTER PUBLICATION OF THE FINAL RULE IN THE FEDERAL REGISTER] or within 180 days after startup of the source, whichever is later, according to §63.7(a)(2)(ix). ( f g ) If your new or reconstructed affected source commenced construction or reconstruction between [INSERT
DATE OF PUBLICATION OF THIS PROPOSED RULE IN THE FEDERAL REGISTER] , and [INSERT DATE 60 DAYS AFTER PUBLICATION OF

THE FINAL RUL E IN THE FEDERAL REGISTER] , and you chose to comply with the proposed emission limits when demonstrating initial compliance, you must conduct a second compliance demonstration for the promulgated emission limits within 3 years after [INSERT DATE 60 DAYS AF TER PUBLICATION OF THE FINAL RULE IN THE FEDERAL REGISTER] or within 3 years after startup of the affected source, whichever is later. ( g h ) If your new or reconstructed affected source commences construction or reconstruction after [INSERT DATE 60 DAYS AF TER PUBLICATION OF THE FINAL RULE IN THE FEDERAL REGISTER] , you must demonstrate initial compliance with the promulgated emission limits no later than 180 days after startup of the source.
§ 63.7515 When must I conduct subsequent performance tests or fue l analyses?220 (a) You must conduct all applicable performance tests according to §63.7520 on an annual basis, unless you follow the requirements listed in paragraphs (b) through ( e ) of this section. Annual performance tests must be completed between 10 and 12 months after the previous performance test, unless you follow the requirements listed in paragraphs (b) through ( e ) of this section. (b) You can conduct performance stack tests less often for a given pollutant if your performance stack tests for the po llutant for at least 3 consecutive years show that

you r emissions are within at or below 75 percent of the emission limit , and if there are no changes in the operation of the affected source or air pollution control equipment that could increase emissions

. In this case, you do not have to conduct a performance test for that pollutant for the next 2 years. You must conduct a performance test during the third year and no more than 36 months after the previous performance test. This reduced testing option do es not apply to performance stack tests for dioxin/furan. If you elect to demonstrate compliance using emission averaging under § 63.7522, you must continue to conduct performance stack tests annually. (c) If your boiler or process heater continues to

m eet the emission limit for the pollutant , you may choose221 to conduct performance stack tests for the pollutant every third year if your emissions are within at or below 75 percent of the emission limit, and if there are no changes in the operation of the aff ected source or air pollution control equipment that could increase emissions , but each such performance test must be conducted no more than 36 months after the previous performance test. This reduced testing option does not apply to performance stack tes ts for dioxin/furan. If you elect to demonstrate compliance using emission averaging under § 63.7522, you must continue to conduct performance stack tests annually. (d) If a performance test shows emissions exceeded 75 percent of the e mission limit, you m ust conduct annual performance tests for that pollutant until all performance

tests over a consecutive 3

- year period show compliance. (e) For affected units in the natural gas/refinery gas subcategory, you are only required to conduct an initial performan ce test for PM, mercury, HCl, and dioxin/furan unless you change the source or supplier of the gaseous fuel. (f (e ) If you are required to meet an ap plicable work practice standard , you must conduct annual performance

tune

- ups according to §63.7520. Each annual tune

- up must Formatted: Indent: First line: 0"222 be conducted between 10 and 12 months after the previous

tune

- up . ( g f ) If you demonstrate compliance with the mercury or HCl based on fuel analysis, y ou must conduct a fuel analysis according to §63.7521 for each type of fuel burned

m onthly

. If you burn a new type of fuel, you must conduct a fuel analysis before burning the new type of fuel in your boiler or process heater. You must still meet all applicable continuous compliance requirements in §63.7540. ( h g ) You must report the re sults of performance tests (stack test and fuel analyses) within 60 days after the completion of the performance tests. This report should must also verify that the operating limits for your affected source have not changed or provide documentation of revi sed operating parameters established according to §63.7530 and Table 7 to this subpart, as applicable. The reports for all subsequent performance tests should must include all applicable information required in §63.7550.
§ 63.7520 What stack tests and pr ocedures must I use for the performance tests ? (a) You must conduct all performance tests according to §63.7(c), (d), (f), and (h). You must also develop a site

- specific test plan according to the requirements in §63.7(c).223 (b) You must conduct each perf ormance test according to the requirements in Table 5 to this subpart. (c) You must conduct each performance stack test under the specific conditions listed in Tables 5 and 7 to this subpart. You must conduct performance stack tests at the maximum normal operating load while burning the type of fuel or mixture of fuels that have ha s the highest content of chlorine , and mercury , and total selected metals , and you must demonstrate initial compliance and establish your operating limits based on these tests. T hese requirements could result in the need to conduct more than one performance test. ( d ) You must conduct three separate test runs for each performance test required in this section, as specified in §63.7(e)(3). Each test run must last at least 4 hour s . ( e ) To determine compliance with the emission limits, you must use the F

- Factor methodology and equations in sections 12.2 and 12.3 of EPA Method 19 of appendix A to part 60 of this chapter to convert the measured particulate matter concentrations, the m easured HCl concentrations, and the measured mercury concentrations that result from the initial performance test to pounds per million Btu heat input emission rates using F

- factors.224

§ 63.7521 What f uel analyses and procedures must I use for the performa nce tests ? (a) You must conduct performance fuel analys is test s according to the procedures in paragraphs (b) through (e) of this section and Table 6 to this subpart, as applicable. (b) You must develop and submit a site

- specific fuel analysis plan to th e EPA Administrator for review and approval according to the following procedures and requirements in paragraphs (b)(1) and (2) of this section. (1) You must submit the fuel analysis plan no later than 60 days before the date that you intend to demonstrat e compliance. (2) You must include the information contained in paragraphs (b)(2)(i) through (vi) of this section in your fuel analysis plan. (i) The identification of all fuel types anticipated to be burned in each boiler or process heater. (ii) For ea ch fuel type, the notification of whether you or a fuel supplier will be conducting the fuel analysis. (iii) For each fuel type, a detailed description of the sample location and specific procedures to be used for collecting and preparing the composite sa mples if your procedures are different from paragraph (c) or (d) of this225
section. Samples should be collected at a location that most accurately represents the fuel type, where possible, at a point prior to mixing with other dissimilar fuel types. (iv) F or each fuel type, the analytical methods from Table 6 , with the expected minimum detection levels, to be used for the measurement of chlorine or mercury. (v) If you request to use an alternative analytical method other than those required by Table 6 to t his subpart, you must also include a detailed description of the methods and procedures that you are proposing to use. Methods in Table 6 shall be used until the requested alternative is approved. (vi) If you will be using fuel analysis from a fuel suppl ier in lieu of site

- specific sampling and analysis, the fuel supplier must use the analytical methods required by Table 6 to this subpart. (c) At a minimum, you must obtain three composite fuel samples for each fuel type according to the procedures in

par agraph (c)(1) or (2) of this section. (1) If sampling from a belt (or screw) feeder, collect fuel samples according to paragraphs (c)(1)(i) and (ii) of this section.226 (i) Stop the belt and withdraw a 6

- inch wide sample from the full cross

- section of the st opped belt to obtain a minimum two pounds of sample. Collect You must c ollect all the material (fines and coarse) in the full cross

- section. Transfer You must t ransfer the sample to a clean plastic bag. (ii) Each composite sample will consist of a minimum of three samples collected at approximately equal 1

- hour intervals during the testing period. (2) If sampling from a fuel pile or truck, you must collect fuel samples according to paragraphs (c)(2)(i) through (iii) of this section. (i) For each composite sample, you must select a minimum of five sampling locations uniformly spaced over the surface of the pile. (ii) At each sampling site, you must dig into the pile to a depth of 18 inches. Insert You must i nsert a clean flat square shovel into the hole an d withdraw a sample, making sure that large pieces do not fall off during sampling. (iii) Transfer You must t ransfer all samples to a clean plastic bag for further processing.227 (d) Prepare You must p repare each composite sample according to the procedures i n paragraphs (d)(1) through (7) of this section. (1) Thoroughly You must t horoughly mix and pour the entire composite sample over a clean plastic sheet. (2) Break You must b reak sample pieces larger than 3 inches into smaller sizes. (3) Make You must m ake a pie shape with the entire composite sample and subdivide it into four equal parts. (4) Separate You must s eparate one of the quarter samples as the first subset. (5) If this subset is too large for grinding, you must repeat the procedure in paragraph (d )(3) of this section with the quarter sample and obtain a one

- quarter subset from this sample. (6) Grind You must g rind the sample in a mill. (7) Use You must u se the procedure in paragraph (d)(3) of this section to obtain a one

- quarter subsample for analy sis. If the quarter sample is too large, subdivide it further using the same procedure. (e) Determine You must d etermine the concentration of pollutants in the fuel (mercury and/or chlorine) in units of pounds per million Btu of each composite sample for e ach228 fuel type according to the procedures in Table 6 to this subpart.
§ 63.7522 Can I use emission averaging to comply with this subpart? (a) As an alternative to meeting the requirements of §63.7500 for particulate matter, HCl, or mercury on a boiler o r process heater

- specific basis , if you have more than one existing boiler or process heater in any subcategory located at your facility, you may demonstrate compliance by emission averaging , if your averaged emissions are within 90 percent of the applicab le emission limit, according to the procedures in this section. (b) Separate stack requirements. For a group of two

or more existing boilers or process heater s in the same subcategory that each vent to a separate stack, you may average particulate matter , HCl , and mercury emissions to demonstrate compliance with the limits in Table 2 to this subpart if you satisfy the requirements in paragraphs (c), (d), (e), (f), and (g) of this section. (c) For each existing boiler or process heater in the averaging gr oup, the emission rate achieved during the initial compliance test for the HAP being averaged must not exceed the emission level that was being achieved on [ INSERT THE DATE 30 DAYS AFTER PUBLICATION OF THE FINAL22 9

RULE IN THE FEDERAL REGISTER ] or the contro l technology employed during the initial compliance test must not be less effective for the HAP being averaged than the control technology employed on [ INSERT THE DATE 30 DAYS AFTER
PUBLICATION OF THE FINAL RULE IN THE FEDERAL REGISTER ]

. (d) The averaged emissions rate from the existing boilers and process heater s participating in the emissions averaging option must be in compliance with the limits in Table 2 to this subpart at all times following the compliance date specified in §63.7495. (e) You must d emonstrate initial compliance according to paragraph (e)(1) or (2) of this section. (1) You must use Equation 1 of this section to demonstrate that the particulate matter, HCl, and mercury emissions from all existing unit s participating in the emissions a veraging option do not exceed the emission limits in Table 2 to this subpart.

Where: Ave Weighted Emissions = Average weighted emissions for particulate matter, HCl, or mercury, in units of pounds per million Btu of heat input. Formatted: Left230 Er = Emission rate (as ca lculated according to Table 5 to this subpart for particulate matter, HCl, or mercury or by fuel analysis for HCl or mercury as calculated by the applicable equation in §63.7530( c)) for unit , i, for particulate matter, HCl, or mercury, in units of pounds p er million Btu of heat input. Hm = Maximum rated heat input capacity of unit , i, in units of million Btu per hour. n = Number of unit s participating in the emissions averaging option. 0.90 = R equired discount factor

. (2) If you are not capable of monitor ing heat input, and the boiler generates steam, you may use Equation 2 of this section as an alternative to using Equation 1 of this section to demonstrate that the particulate matter, HCl, and mercury emissions from all existing units participating in the emissions averaging option do not exceed the emission limits in Table 2 to this subpart.

Where: Ave Weighted Emissions = Average weighted emission level for PM, HCl, or mercury, in units of pounds per million Btu of heat input. E r = Emission rate (as ca lculated according to Table 5 to this subpart for particulate matter, HCl, or mercury or by fuel analysis for HCl or mercury as calculated by the applicable equation in §63.7530( c)) for unit , i, for particulate matter, HCl, or mercury, in units of pounds p er million Btu of heat input. Sm = Maximum steam generation by unit , i, in units of pounds.231 Cf = Conversion factor, calculated from the most recent compliance test, in units of million Btu of heat input per pounds of steam generated for unit, i

. 0.90 = Req uired discount factor. (f) You must demonstrate co mpliance on a monthly basis determined at the end of every month (12 times per year) according to paragraphs (f)(1) through (3) of this section. The first monthly period begins on the compliance date

spec ified in §63.7495. (1) For each calendar month, you must use Equation 3 of this section to calculate the monthly average weighted emission rate using the actual heat capacity for each existing unit participating in the emissions averaging option.

Where : Ave Weighted Emissions = monthly average weighted emission level for particulate matter, HCl, or mercury, in units of pounds per million Btu of heat input. Er = Emission rate, (as calculated during the most recent compliance test, (as calculated accordin g to Table 5 to this subpart for particulate matter, HCl, or mercury or by fuel analysis for HCl or mercury as calculated by the applicable equation in §63.7530( c)) for unit , i, for particulate matter, HCl, or mercury, in units of pounds per million Btu of heat input. Hb = The average heat input for each calendar month of boiler, i, in units of million Btu. Formatted: Left232

n = Number of unit s participating in the emissions averaging option. 0.90 = Required discount factor. (2) If you are not capable of monitoring heat in put, you may use Equation 4 of this section as an alternative to using Equation 3 of this section to calculate the monthly weighted emission rate using the actual steam generation from the unit s participating in the emissions averaging option.

Where:

Ave Weighted Emissions = monthly average weighted emission level for PM, HCl, or mercury, in units of pounds per million Btu of heat input. Er = Emission rate, (as calculated during the most recent compliance test (as calculated according to Table 5 to this s ubpart for particulate matter, HCl, or mercury or by fuel analysis for HCl or mercury as calculated by the applicable equation in §63.7530( c)) for unit , i, for particulate matter, HCl, or mercury, in units of pounds per million Btu of heat input. Sa = Actu al steam generation for each calendar month by boiler, i, in units of pounds. Cf = Conversion factor, as calculated during the most recent compliance test, in units of million Btu of heat input per pounds of steam generated for unit, i

. 0.90 = Required dis count factor. (3) Until 12 monthly weighted average emission rates have been accumulated, calculate and report only the monthly average weighted emission rate determined under paragraph (f)(1) or (2) of this section. After 12 monthly233 weighted average em ission rates have been accumulated, for each subsequent calendar month, use Equation 5 of this section to calculate the 12

- month rolling average of the monthly weighted average emission rates for the current month and the previous 11 months.

Where: Eavg = 12

- month rolling average emission rate, (pounds per million Btu heat input) ERi = Monthly weighted average, for month “i”, (pounds per million Btu heat input)(as calculated by (f)(1) or (2)) (g) You must develop , and submit to the applicable regulatory authority for review and approval upon request, an implementation plan for emission averaging according to the following procedures and requirements in paragraphs (g)(1) through (4). (1) You must submit the implementation plan no later than 180 days befo re the date that the facility intends to demonstrate compliance using the emission averaging option. (2) You must include the information contained in paragraphs (g)(2)(i) through (vii) of this section in your implementation plan for all emission sources included in an emissions average:234 (i) The identification of all existing boilers and process heater s in the averaging group, including for each either the applicable HAP emission level or the control technology installed as of [INSERT DATE 60 DAYS AFTER

P UBLICATION OF THE FINAL RULE IN THE FEDERAL REGISTER] and the date on which you are requesting emission averaging to

commence ; (ii) The process parameter (heat input or steam generated) that will be monitored for each averaging group; (iii) The specific control technology or pollution prevention measure to be used for each emission boiler or process heater in the averaging group and the date of its installation or application. If the pollution prevention measure reduces or eliminates emissions from multi ple boilers or process heater s, the owner or operator must identify each boiler or process heater ; (iv) The test plan for the measurement of particulate matter, HCl, or mercury emissions in accordance with the requirements in §63.7520; (v) The operating parameters to be monitored for each control system or device consistent with 63.7500 and Table 4, and a description of how the operating limits will be determined;235 (vi) If you request to monitor an alternative operating parameter pursuant to §63.7525, you must also include: (A) A description of the parameter(s) to be monitored and an explanation of the criteria used to select the parameter(s); and (B) A description of the methods and procedures that will be used to demonstrate that the parameter indicate s proper operation of the control device; the frequency and content of monitoring, reporting, and recordkeeping requirements; and a demonstration, to the satisfaction of the applicable regulatory authority, that the proposed monitoring frequency is suffici ent to represent control device operating conditions; and (vii) A demonstration that compliance with each of the applicable emission limit(s) will be achieved under representative operating conditions. (3) T he regulatory authority shall review and approv e or disapprove the plan according to the following criteria: (i) Whether the content of the plan includes all of the information specified in paragraph (g)(2) of this section; and236 (ii) Whether the plan presents sufficient information to determine that c ompliance will be achieved and maintained. (4) The applicable regulatory authority shall not approve an emission averaging implementation plan containing any of the following provisions: (i) Any averaging between emissions of differing pollutants or betw een differing sources; or (ii) The inclusion of any emission source other than an existing unit in the same subcategory

. (h) Common stack requirements. For a group of two or more existing affected unit s, each of which vents through a single common stack, you may average particulate matter, HCl and mercury emissions to demonstrate compliance with the limits in Table 2 to this subpart if you satisfy the requirements in paragraph (i) or (j) of this section. (i) For a group of two or more existing units in t he same subcategory , each of which vents through a common emissions control system to a common stack, that does not receive emissions from units in other subcategories or categories, you may treat such averaging group as a single existing unit for purposes of this subpart and comply with the requirements of this subpart as if the group were a single unit

.237 (j) For all other groups of unit s subject to paragraph (h) of this section, the owner or operator may elect to: (1) Conduct performance tests according to procedures specified in §63.7520 in the common stack if affected units from other subcategories vent to the common stack . T he emission limits that the group must comply with are determined by the use of equation 6.

Where:

E n = HAP emission limit, l b/MM Btu , ppm, or ng/dscm ;
EL i = Appropriate emission limit from Table 2 to this subpart for unit i , in units of lb/MMBtu , ppm or ng/dscm ;
H i = Heat input from unit i , MMBtu; ( 2 ) Conduct performance tests according to procedures specified in §63.7520 in the commo n stack . I f affected units from nonaffected units vent to the common stack, the units from nonaffected units must be shut down or vented to a different stack during the performance test); and ( 3 ) Meet the applicable operating limit specified in §63.7540 and Table 8 to this subpart for each emissions control system (except that, if each unit venting to the common stack has an applicable opacity operating limit,238 then a single continuous opacity monitoring system may be located in the common stack instead of in each duct to the common stack). (k) Combination requirements. The common stack of a group of two or more existing boilers or process heaters in the same subcategory subject to paragraph (h) of this section may be treated as a separate stack for purpos es of paragraph (b) of this section and included in an emissions averaging group subject to paragraph (b) of this section.
§ 63.7525 What are my monitoring, installation, operation, and maintenance requirements? (a) If your boiler or process heater has a heat input capacity of 100 MMBtu per hour or greater, you must install, operate, and maintain a continuous emission monitoring system (CEMS) for CO and oxygen according to the procedures in paragraphs (a)(1) through (6) of this section by the compliance date specified in §63.7495. The CO and oxygen shall be monitored at the same location at the outlet of the boiler or process heater. (1) Each CEMS must be installed, operated, and maintained according to the applicable procedures under Performance Specifi cation (PS ) 3 or 4A of 40 CFR part 60, appendix B, and according to the site

- specific monitoring plan developed according to §63.7505(d). Formatted: No underline239 (2) You must conduct a performance evaluation of each CEMS according to the requirements in §63.8 and according

to PS 4A of 40 CFR part 60, appendix B. (3) Each CEMS must complete a minimum of one cycle of operation (sampling, analyzing, and data recording) for each successive 15

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

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

- day rolling average emission rate is calculated as the average of all of the hourly CO emission data for the preceding 30 operating days. (6) For purposes of calcula ting data averages, you

m ust use all the data collected during all periods in assessing compliance. Any period for which the monitoring system is out of control and data are not available for required calculations constitutes a deviation from the monitori ng requirements. (b) If your boiler or process heater has a heat input capacity of 250 MMBtu per hour or greater and combust combust s coal, biomass, or residual oil , you must install, certify, Formatted: No underline240 maintain, and operate a CEMS measuring PM emissions discharged t o the atmosphere and record the output of the system as specified in paragraphs ( b )(1) through ( b )( 6 ) of this section. (1) Each CEMS shall be installed, certified, operated, and maintained according to the requirements in §6 3

. 7540 ( a ) (8)

. ( 2 ) The initial pe rformance evaluation shall be completed no later than 180 days after the date of initial startup of a new unit or within 180 days of the compliance date for an existing unit, as specified under §6 3

. 7495 of this subpart

. ( 3 ) Compliance with the applicable e missions limit shall be determined based on the 24

- hour daily (block) average of the hourly arithmetic average emissions concentrations using the continuous monitoring system outlet data. The 24

- hour block arithmetic average emission concentration shall b e calculated using EPA Reference Method 19 of appendix A of 40 CFR part 60

. ( 4 ) Obtain valid CEMS hourly averages for all operating hours on a 30

- day rolling average basis. At least two data points per hour shall be used to calculate each 1

- hour arithmeti c average.241
( 5 ) The 1

- hour arithmetic averages required shall be expressed in lb /MMBtu and shall be used to calculate the boiler operating day daily arithmetic average emission s. ( 6 ) When PM emissions data are not obtained because of CEMS breakdowns, repair s, calibration checks, and zero and span adjustments, emissions data shall be obtained by using other monitoring systems as approved by the Administrator or EPA Reference Method 19 of appendix A of 40 CFR part 60 to provide, as necessary, valid emissions d ata for all operating hours per 30

- day rolling average. ( c ) If you have an applicable opacity operating limit, you must install, operate, certify and maintain each continuous opacity monitoring system (COMS) according to the procedures in paragraphs ( c )(1 ) through (7) of this section by the compliance date specified in §63.7495. (1) Each COMS must be installed, operated, and maintained according to PS 1 of 40 CFR part 60, appendix B. (2) You must conduct a performance evaluation of each COMS according to the requirements in §63.8 and according to PS 1 of 40 CFR part 60, appendix B. (3) As specified in §63.8(c)(4)(i), each COMS must complete a minimum of one cycle of sampling and analyzing for each successive 10

- second period and one cycle of data recordi ng for each successive 6

- minute period.242 (4) The COMS data must be reduced as specified in §63.8(g)(2). (5) You must include in your site

- specific monitoring plan procedures and acceptance criteria for operating and maintaining each COMS according to the requirements in §63.8(d). At a minimum, the monitoring plan must include a daily calibration drift assessment, a quarterly performance audit, and an annual zero alignment audit of each COMS. (6) You must operate and maintain each COMS according to the re quirements in the monitoring plan and the requirements of §63.8(e). You must i dentify 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 ze ro alignment audit. Any 6

- minute period for which the monitoring system is out of control and data are not available for required calculations constitutes a deviation from the monitoring requirements. (7) You must determine and record all the 6

- minute

av erages (and 1

- hour block averages as applicable) collected for periods during which the COMS is not out of control. ( d ) If you have an operating limit that requires the use of a CMS, you must install, operate, and maintain each243 continuous parameter monito ring system (CPMS) according to the procedures in paragraphs ( d )(1) through (5) of this section by the compliance date specified in §63.7495. (1) The CPMS must complete a minimum of one cycle of operation for each successive 15

- minute period. You must ha ve a minimum of four successive cycles of operation to have a valid hour of data. (2) Except for monitoring malfunctions, associated repairs, and required quality assurance or control activities (including, as applicable, calibration checks and required z ero and span adjustments), you must conduct all monitoring in continuous operation at all times that the unit is operating. A monitoring malfunction is any sudden, infrequent, not reasonably preventable failure of the monitoring to provide valid data. Mon itoring failures that are caused in part by poor maintenance or careless operation are not malfunctions. (3) For purposes of calculating data averages, you must not use data recorded during monitoring malfunctions, associated repairs, out of control perio ds, or required quality assurance or control activities. You must use all the data collected during all other periods in assessing compliance. Any 15

- minute period for which the monitoring system is out

- of

- control and data are not available for244 required calculations constitutes a deviation from the monitoring requirements. (4) Determine You must d etermine the 3

- hour block average of all recorded readings, except as provided in paragraph (c)(3) of this section. (5) Record You must r ecord the results of eac h inspection, calibration, and validation check. ( e ) If you have an operating limit that requires the use of a flow measurement device, you must meet the requirements in paragraphs ( d ) and ( e )(1) through (4) of this section. (1) Locate You must l ocate the flow sensor and other necessary equipment in a position that provides a representative flow. (2) Use You must u se a flow sensor with a measurement sensitivity of 2 percent of the flow rate. (3) Reduce You must r educe swirling flow or abnormal velocity dis tributions due to upstream and downstream disturbances. (4) Conduct You must c onduct a flow sensor calibration check at least semiannually. ( f ) If you have an operating limit that requires the use of a pressure measurement device, you must meet the245 requir ements in paragraphs ( d ) and ( f )(1) through (6) of this section. (1) L ocate the pressure sensor(s) in a position that provides a representative measurement of the pressure. (2) M inimize or eliminate pulsating pressure, vibration, and internal and externa l corrosion. (3) U se a gauge with a minimum tolerance of 1.27 centimeters of water or a transducer with a minimum tolerance of 1 percent of the pressure range. (4) C heck pressure tap pluggage daily. (5) Using a manometer, you must check gauge calibratio n quarterly and transducer calibration monthly. (6) C onduct calibration checks any time the sensor exceeds the manufacturer's specified maximum operating pressure range or install a new pressure sensor. ( g ) If you have an operating limit that requires th e use of a pH measurement device, you must meet the requirements in paragraphs ( d ) and ( g )(1) through (3) of this section. (1) Locate the pH sensor in a position that provides a representative measurement of scrubber effluent pH. (2) Ensure the sample is properly mixed and representative of the fluid to be measured.246 (3) Check the pH meter's calibration on at least two points every 8 hours of process operation. ( h ) If you have an operating limit that requires the use of equipment to monitor voltage and s econdary amperage (or total power input) of an electrostatic precipitator (ESP), you must use voltage and secondary current monitoring equipment to measure voltage and secondary current to the ESP. ( i ) If you have an operating limit that requires the

use of equipment to monitor sorbent injection rate ( e.g. , weigh belt, weigh hopper, or hopper flow measurement device), you must meet the requirements in paragraphs (c) and ( i )(1) through (3) of this section. (1) Locate the device in a position(s) that prov ides a representative measurement of the total sorbent injection

rate. (2) Install and calibrate the device in accordance with manufacturer's procedures and specifications. (3) At least annually, calibrate the device in accordance with the manufacturer's procedures and specifications. ( j ) If you elect to use a fabric filter bag leak detection system to comply with the requirements of this subpart, you must install, calibrate, maintain, and247 continuously operate a bag leak detection system as specified in paragraphs ( j )(1) through (8) of this section. (1) You must install and operate a bag leak detection system for each exhaust stack of the fabric filter. (2) Each bag leak detection system must be installed, operated, calibrated, and maintained in a manne r consistent with the manufacturer's written specifications and recommendations and in accordance with the guidance provided in EPA

– 454/R

– 98

– 015, September 1997. (3) The bag leak detection system must be certified by the manufacturer to be capable of dete cting particulate matter emissions at concentrations of 10 milligrams per actual cubic meter or less. (4) The bag leak detection system sensor must provide output of relative or absolute particulate matter loadings. (5) The bag leak detection system must be equipped with a device to continuously record the output signal from the sensor. (6) The bag leak detection system must be equipped with an alarm system that will sound automatically when an increase in relative particulate matter emissions over a

pre set level is detected. The alarm must be located where it is easily heard by plant operating personnel.248 (7) For positive pressure fabric filter systems that do not duct all compartments of cells to a common stack, a bag leak detection system must be insta lled in each baghouse compartment or cell. (8) Where multiple bag leak detectors are required, the system's instrumentation and alarm may be shared among detectors.
§ 63.7530 How do I demonstrate initial compliance with the emission limits and work prac tice standards? (a) You must demonstrate initial compliance with each emission limit that applies to you by conducting initial performance tests (performance stack tests and fuel analyses) and establishing operating limits, as applicable, according to §63 .7520, paragraph (c) of this section, and Tables 5 and 7 to this subpart. (b) If you demonstrate compliance through performance stack testing, you must establish each site

- specific operating limit in Table 2 to this subpart that applies to you according t o the requirements in §63.7520, Table 7 to this subpart, and paragraph (c)(4) of this section, as applicable. You must also conduct fuel analyses according to §63.7521 and establish maximum fuel pollutant input levels according to paragraphs (c)(1) through (3) of this section, as applicable.249 (1) You must establish the maximum chlorine fuel input (C input ) during the initial performance testing according to the procedures in paragraphs (c)(1)(i) through (iii) of this section. (i) You must determine the fuel type or fuel mixture that you could burn in your boiler or process heater that has the highest content of chlorine. (ii) During the performance testing for HCl, you must determine the fraction of the total heat input for each fuel type burned (Q i ) based on the fuel mixture that has the highest content of chlorine, and the average chlorine concentration of each fuel type burned (C i ). (iii) You must establish a maximum chlorine input level using Equation 7 of this section.

Where: Cl input = Maximum amo unt of chlorine entering the boiler or process heater through fuels burned in units of pounds per million Btu. C i = Arithmetic average concentration of chlorine in fuel type, i, analyzed according to §63.7521, in units of pounds per million Btu. Q i = Fra ction of total heat input from fuel type, i, based on the fuel mixture that has the highest content of chlorine. If you do not burn multiple fuel types during the250 performance testing, it is not necessary to determine the value of this term. Insert a value of “1” for Q i . n = Number of different fuel types burned in your boiler or process heater for the mixture that has the highest content of chlorine.

(2) You must establish the maximum mercury fuel input level (Mercury input ) during the initial performance testing using the procedures in paragraphs (c)(3)(i) through (iii) of this section. (i) You must determine the fuel type or fuel mixture that you could burn in your boiler or process heater that has the highest content of mercury. (ii) During the compli ance demonstration for mercury, you must determine the fraction of total heat input for each fuel burned (Q i ) based on the fuel mixture that has the highest content of mercury, and the average mercury concentration of each fuel type burned (HG i ). (iii) Yo u must establish a maximum mercury input level using Equation 8 of this section.

Where: Mercury input = Maximum amount of mercury entering the boiler or process heater through fuels burned in units of pounds per million Btu.251

HG i = Arithmetic average conce ntration of mercury in fuel type, i, analyzed according to §63.7521, in units of pounds per million Btu. Q i = Fraction of total heat input from fuel type, i, based on the fuel mixture that has the highest mercury content. If you do not burn multiple fuel t ypes during the performance test, it is not necessary to determine the value of this term. Insert a value of “1” for Q i . n = Number of different fuel types burned in your boiler or process heater for the mixture that has the highest content of mercury.

( 3 ) You must establish parameter operating limits according to paragraphs (c)(4)(i) through (iv) of this section. (i) For a wet scrubber, you must establish the minimum scrubber effluent pH, liquid flowrate, and pressure drop as defined in §63.7575, as yo ur operating limits during the three

- run performance test. If you use a wet scrubber and you conduct separate performance tests for particulate matter, HCl, and mercury emissions, you must establish one set of minimum scrubber effluent pH, liquid flowrate, and pressure drop operating limits. The minimum scrubber effluent pH operating limit must be established during the HCl performance test. If you conduct multiple performance tests, you must set the minimum liquid flowrate and pressure drop operating limit s at the highest minimum values established during the performance tests.252 (ii) For an electrostatic precipitator, you must establish the minimum voltage and secondary current (or total power input), as defined in §63.7575, as your operating limits during the three

- run performance test. (iii) For a dry scrubber, you must establish the minimum sorbent injection rate, as defined in §63.7575, as your operating limit during the three

- run performance test. (iv) The operating limit for boilers or process heater s with fabric filters that choose to demonstrate continuous compliance through bag leak detection systems is that a bag leak detection system be installed according to the requirements in §63.7525, and that each fabric filter must be operated such that the bag leak detection system alarm does not sound more than 5 percent of the operating time during a 6

- month period. ( c ) If you elect to demonstrate compliance with an applicable emission limit through fuel analysis, you must conduct fuel analyses according to §63.7521 and follow the procedures in paragraphs ( c )(1) through (5) of this section. (1) If you burn more than one fuel type, you must determine the fuel mixture you could burn in your boiler or process heater that would result in the maximum emission253 rates of the pollutants that you elect to demonstrate compliance through fuel analysis. (2) You must determine the 90th percentile confidence level fuel pollutant concentration of the composite samples analyzed for each fuel type using the one

- sided z

- st atistic test described in Equation 9 of this section.

Where:

P 90 = 90th percentile confidence level pollutant concentration, in pounds per million Btu. mean = Arithmetic average of the fuel pollutant concentration in the fuel samples analyzed according to §63.7521, in units of pounds per million Btu. SD = Standard deviation of the pollutant concentration in the fuel samples analyzed according to §63.7521, in units of pounds per million Btu. t = t distribution critical value for 90th percentile (0.1) p robability for the appropriate degrees of freedom (number of samples minus one) as obtained from a Distribution Critical Value Table.

(3) To demonstrate compliance with the applicable emission limit for HCl, the HCl emission rate that you calculate for y our boiler or process heater using Equation 10 of this section must not exceed the applicable emission limit for HCl.254

Where: HCl = HCl emission rate from the boiler or process heater in units of pounds per million Btu. C i90 = 90th percentile confidence level concentration of chlorine in fuel type, i, in units of pounds per million Btu as calculated according to Equation 8 of this section. Q i = Fraction of total heat input from fuel type, i, based on the fuel mixture that has the highest content of chlori ne. If you do not burn multiple fuel types, it is not necessary to determine the value of this term. Insert a value of “1” for Q i . n = Number of different fuel types burned in your boiler or process heater for the mixture that has the highest content of c hlorine. 1.028 = Molecular weight ratio of HCl to chlorine.

(4) To demonstrate compliance with the applicable emission limit for mercury, the mercury emission rate that you calculate for your boiler or process heater using Equation 11 of this section mu st not exceed the applicable emission limit for mercury.

Where: Mercury = Mercury emission rate from the boiler or process heater in units of pounds per million Btu. HG i90 = 90th percentile confidence level concentration of mercury in fuel, i, in units of pounds per million Btu as calculated according to Equation 8 of this section. Q i = Fraction of total heat input from fuel type, i, based on the fuel mixture that has the highest mercury content. If you do not burn multiple fuel types, it is not necessar y to determine the value of this term. Insert a value of “1” for Q i .255 n = Number of different fuel types burned in your boiler or process heater for the mixture that has the highest mercury content.

(d) If you own or operate an existing unit with a heat input capacity of 10 million Btu per hour or less, you must submit a signed statement in the Notification of Compliance Status report that indicates that you conducted a tune

- up of the unit

. ( e ) You must submit the energy a ssessment report, along with a s igned certification that the assessment is an accurate depiction of your facility. ( f ) You must submit the Notification of Compliance Status containing the results of the initial compliance demonstration according to the requirements in §63.7545(e).
**CONTI NUOUS COMPLIANCE REQUIREMENTS**  § 63.7535 How do I monitor and collect data to demonstrate continuous compliance? (a) You must monitor and collect data according to this section and the site

- specific monitoring pla n required by §63.7505(d). (b) Except for monitor malfunctions, associated repairs, and required quality assurance or control activities (including, as applicable, calibration checks and required zero and span adjustments), you must monitor256 continuously ( or collect data at all required intervals) at all times that the affected source is operating. (c) You may not use data recorded during monitoring malfunctions, associated repairs, or required quality assurance or control activities in data averages and

c alculations used to report emission or operating levels. You must use all the data collected during all other periods in assessing the operation of the control device and associated control system.
§ 63.7540 How do I demonstrate continuous compliance wi th the emission limits and work practice standards? (a) You must demonstrate continuous compliance with each emission limit, operating limit, and work practice standard in Tables 1 through 3 to this subpart that applies to you according to the methods spe cified in Table 8 to this subpart and paragraphs (a)(1) through (10) of this section. (1) Following the date on which the initial performance test is completed or is required to be completed under §§63.7 and 63.7510, whichever date comes first, you must n ot operate above any of the applicable maximum operating limits or below any of the applicable minimum operating limits listed in Table 4 to this subpart

at a ny times. Operation above the established maximum or257 below the established minimum operating limi ts shall constitute a deviation of established operating limits. Operating limits are must be confirmed or reestablished during performance tests

. (2) As specified in §63.7 550(c), y ou must keep records of the type and amount of all fuels burned in each bo iler or process heater during the reporting period to demonstrate that all fuel types and mixtures of fuels burned would either result in lower emissions of HCl and mercury, than the applicable emission limit for each pollutant (if you demonstrate complian ce through fuel analysis), or result in lower fuel input of chlorine and mercury than the maximum values calculated during the last performance tests (if you demonstrate compliance through performance stack testing). (3) If you demonstrate compliance with an applicable HCl emission limit through fuel analysis and you plan to burn a new type of fuel, you must recalculate the HCl emission rate using Equation 9 of §63.7530 according to paragraphs (a)(3)(i) through (iii) of this section. (i) You must determin e the chlorine concentration for any new fuel type in units of pounds per million Btu, based on supplier data or your own fuel analysis, according to258 the provisions in your site

- specific fuel analysis plan developed according to §63.7521(b). (ii) You must determine the new mixture of fuels that will have the highest content of chlorine. (iii) Recalculate the HCl emission rate from your boiler or process heater under these new conditions using Equation 9 of §63.7530. The recalculated HCl emission rate

must be less than the applicable emission limit. (4) If you demonstrate compliance with an applicable HCl emission limit through performance testing and you plan to burn a new type of fuel or a new mixture of fuels, you must recalculate the maximum chlorine i nput using Equation 5 of §63.7530. If the results of recalculating the maximum chlorine input using Equation 5 of §63.7530 are higher than the maximum chlorine input level established during the previous performance test, then you must conduct a new perfor mance test within 60 days of burning the new fuel type or fuel mixture according to the procedures in §63.7520 to demonstrate that the HCl emissions do not exceed the emission limit. You must also establish new operating limits based on this performance te st according to the procedures in §63.7530(c). (5) If you demonstrate compliance with an applicable mercury emission limit through fuel analysis, and you plan259 to burn a new type of fuel, you must recalculate the mercury emission rate using Equation 11 of §63.7530 according to the procedures specified in paragraphs (a)(7)(i) through (iii) of this section. (i) You must determine the mercury concentration for any new fuel type in units of pounds per million Btu, based on supplier data or your own fuel analys is, according to the provisions in your site

- specific fuel analysis plan developed according to §63.7521(b). (ii) You must determine the new mixture of fuels that will have the highest content of mercury. (iii) Recalculate the mercury emission rate from your boiler or process heater under these new conditions using Equation 11 of §63.7530. The recalculated mercury emission rate must be less than the applicable emission limit. ( 6 ) If you demonstrate compliance with an applicable mercury emission limit thr ough performance testing, and you plan to burn a new type of fuel or a new mixture of fuels, you must recalculate the maximum mercury input using Equation 7 of §63.7530. If the results of recalculating the maximum mercury input using Equation 7 of §63.7530 are higher than the maximum mercury input level established during the previous performance test, then you must conduct a new performance test within 60 days of burning the new260 fuel type or fuel mixture according to the procedures in §63.7520 to demonstra te that the mercury emissions do not exceed the emission limit. You must also establish new operating limits based on this performance test according to the procedures in §63.7530(c). ( 7 ) If your unit is controlled with a fabric filter, and you demonstrat e continuous compliance using a bag leak detection system, you must initiate corrective action within 1 hour of a bag leak detection system alarm and complete corrective actions as soon as practical, and operate and maintain the fabric filter system such t hat the alarm does not sound more than 5 percent of the operating time during a 6

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

- month period that the alarm sounds. In calculating this operating time percentage, if inspection of the fabric filter demonstrates that no corrective action is required, no alarm time is counted. If corrective action is required, each alarm shall be counted as a minimum of 1 hour. If you take longer than 1 hour to initiate corrective action, the alarm time shall be261

counted as the act ual amount of time taken to initiate corrective action. ( 8 ) If you are required to install a CEMS according to §63.7525(a), then you must meet the requirements in paragraphs (a)( 8 )(i) through (iii) of this section. (i) You must continuously monitor CO ac cording to §§63.7525(a) and 63.7535. (ii) Maintain a CO emission level below or at your applicable CO standard in Table s 1 or 2 to this subpart at all times. (iii) Keep records of CO levels according to §63.7555(b). (9) The owner or operator of an affec ted source using
a CEMS measuring PM emissions to meet requirements of this subpart shall install, certify, operate, and maintain the CEMS as specified in paragraphs ( a )( 9 ) (i) through ( a )( 9 ) (iv) of this section. ( i ) The owner or operator shall conduct a pe rformance evaluation of the CEMS according to the applicable requirements of §60.13 of 40 CFR , Performance Specification 11 in appendix B of 40 CFR part 60 , and procedure 2 in appendix F of 40 CFR part 60

. ( ii ) During each PM correlation testing run of the CEMS required by Performance Specification 11 in appendix B262

of 40 CFR part 60 , PM and O2 (or CO2) data shall be collected concurrently (or within a 30

- to 60

- minute period) by both the CEMS and conducting performance tests using Method 5 or 5B of appendix A

– 3 of 40 CFR part 60 or Method
17 of appendix A

– 6 of 40 CFR part 60

. ( iii ) Quarterly accuracy determinations and daily calibration drift tests shall be performed in accordance with procedure 2 in appendix F of 40 CFR part 60

. Relative Response Audits mus t be performed annually and Response Correlation Audits must be performed every 3 years. ( iv ) After December 31, 2011, within 60 days after the date of completing each performance evaluation conducted to demonstrate compliance with this subpart, the owner or operator of the affected facility must submit the test data to EPA by successfully entering the data electronically into EPA’s WebFIRE database through EPA’s Central Data Exchange. The owner or operator of an affected facility shall enter the test data into EPA’s data base using the Electronic Reporting Tool (ERT) or other compatible electronic spreadsheet. (10) You must conduct a tune

- up of the boiler or process heater annually to demonstrate continuous compliance as specified in paragraphs (a)(10)( i) through (a)(10)(vi) of this section.263 (i) Inspect the burner, and clean or replace any components of the burner as necessary; (ii) Inspect the flame pattern and make any adjustments to the burner necessary to optimize the flame pattern consistent wit h the manufacturer’s specifications; (iii) Inspect the system controlling the air

- to

- fuel ratio, and ensure that it is correctly calibrated and functioning properly; (iv) Minimize total emissions of CO consistent with the manufacturer’s specifications; (v) Measure the concentration in the effluent stream of CO in parts per million, by volume, dry basis (ppmvd), before and after the adjustments are made; and (vi) Maintain on

- site and submit, if requested by the Administrator, an annual report contain ing the information in paragraphs (b)(6)(i) through (iii) of this section, (i) The concentrations of CO in the effluent stream in ppmvd, and oxygen in percent dry basis, measured before and after the adjustments of the boiler; (ii) A description of any corrective actions taken as a part of the combustion adjustment; and (iii) The type and amount of fuel used over the 12 months prior to the annual adjustment.264 (b) You must report each instance in which you did not meet each emission limit and operating limit in Tables 1 through 4 to this subpart that apply to you. You must also report each instance during a startup, shutdown, or malfunction when you did not meet each applicable emission limit and operating limit. These instances are deviations from the emission limits in this subpart. These deviations must be reported according to the requirements in §63.7550.
§ 63.7541 How do I demonstrate continuous compliance under the emission averaging provision? (a) Following the compliance date, the owner or operator must demonstrate compliance with this subpart on a continuous basis by meeting the requirements of paragraphs (a)(1) through (5) of this section. (1) For each calendar month, demonstrate compliance with the average weighted emissions limit for th e existing unit s participating in the emissions averaging option as determined in §63.7522(f) and (g); (2) You must maintain the applicable opacity limit according to paragraphs (a)(2)(i) through (ii) of this section. (i) For each existing unit participa ting in the emissions averaging option that is equipped with a dry265 control system and not vented to a common stack, maintain opacity at or below the applicable limit. (ii) For each group of unit s participating in the emissions averaging option where each unit in the group is equipped with a dry control system and vented to a common stack that does not receive emissions from nonaffected units, maintain opacity at or below the applicable limit at the common stack; (3) For each existing unit participating in the emissions averaging option that is equipped with a wet scrubber, maintain the 3

- hour average parameter values at or below the operating limits established during the most recent performance test; and (4) For each existing unit participating in the

em issions averaging option that has an approved alternative operating plan, maintain the 3

- hour average parameter values at or below the operating limits established in the most recent performance test. (5) For each existing unit participating in the emissi ons averaging option venting to a common stack configuration containing affected units from other subcategories, maintain the appropriate operating limit for each unit as specified in Table 4 to this subpart that applies.266 (b) Any instance where the owner or operator fails to comply with the continuous monitoring requirements in paragraphs (a)(1) through (5) of this section is a deviation. **Notification, Reports, and Records**
§ 63.7545 What notifications must I submi t and when? (a) You must submit all of the notifications in §§63.7(b) and (c), 63.8 (e), (f)(4) and (6), and 63.9 (b) through (h) that apply to you by the dates specified. (b) As specified in §63.9(b)(2), if you startup your affected source before [DATE SIXTY DAYS AFTER PUBLICATION OF THE FINAL RULE IN THE FEDERAL REGISTER], you must submit an Initial Notification not later than 120 days after [DATE
SIXTY DAYS AFTER PUBLICATION OF THE FINAL RULE IN THE FEDERAL REGISTER]. (c) As specified in §63.9(b)(4) a nd (b)(5), if you startup your new or reconstructed affected source on or after [DATE SIXTY DAYS AFTER PUBLICATION OF THE FINAL RULE IN THE FEDERAL REGISTER] , you must submit an Initial Notification not later than 15 days after the actual date of startup o f the affected source. (d) If you are required to conduct a performance test you must submit a Notification of Intent to conduct a267 performance test at least 30 days before the performance test is scheduled to begin. (e) If you are required to conduct an initial compliance demonstration as specified in §63.7530(a), you must submit a Notification of Compliance Status according to §63.9(h)(2)(ii). For each initial compliance demonstration, you must submit the Notification of Compliance Status, including all performance test results and fuel analyses, before the close of business on the 60th day following the completion of the performance test and/or other initial compliance demonstrations according to §63.10(d)(2). The Notification of Compliance Status repo rt must contain all the information specified in paragraphs (e)(1) through (9), as applicable. (1) A description of the affected source(s) including identification of which subcategory the source is in, the design capacity of the source, a description of the add

- on controls used on the source , description of the fuel(s) burned, including whether the fuel(s) were determined by you or EPA through a petition process to be a non

- waste under 40 CFR 241.3, and whether the fuel(s) were processed from discarded no n - hazardous secondary materials within the meaning of 40 CFR 241.3, and justification for the selection of fuel(s) burned during the performance test.268 (2) Summary of the results of all performance tests (stack tests and fuel analyses ) and calculations con ducted to demonstrate initial compliance including all established operating limits. (3) A summary of the CO emissions monitoring data and the maximum CO emission levels recorded during the performance test to show that you have met any applicable emissio n standard in Table 1 or 2 to this subpart. (4) Identification of whether you plan to demonstrate compliance with each applicable emission limit through performance stack testing or fuel analysis. (5) Identification of whether you plan to demonstrate

com pliance by emissions averaging. (6) A signed certification that you have met all applicable emission limits and work practice standards. (7) If you had a deviation from any emission limit , work practice standard, or operating limit, you must also submit a description of the deviation, the duration of the deviation, and the corrective action taken in the Notification of Compliance Status report. ( f ) If you operate a gaseous fuel unit natural gas

fired boiler or process heater that is subject to the emissio n limits specified in Table 1 or 2 to this subpart, and you intend to use a fuel other than natural gas or269 equivalent to fire the affected unit, you must submit a notification of alternative fuel use within 48 hours of the declaration of a period of natura l gas curtailment or supply interruption, as defined in §63.7575. The notification must include the information specified in paragraphs ( f )(1) through (5) of this section. (1) Company name and address. (2) Identification of the affected unit. (3) Reason you are unable to use natural gas or equivalent fuel, including the date when the natural gas curtailment was declared or the natural gas supply interruption began. (4) Type of alternative fuel that you intend to use. (5) Dates when the alternative fuel use is expected to begin and end.
§ 63.7550 What reports must I submit and when? (a) You must submit each report in Table 9 to this subpart that applies to you. (b) Unless the EPA Administrator has approved a different schedule for submission of repor ts under §63.10(a), you must submit each report by the date in Table 9 to this subpart and according to the requirements in paragraphs (b)(1) through (5) of this section.270 (1) The first compliance report must cover the period beginning on the compliance da te that is specified for your affected source in §63.7495 and ending on June 30 or December 31, whichever date is the first date that occurs at least 180 days after the compliance date that is specified for your source in §63.7495. (2) The first complianc e report must be postmarked or delivered no later than July 31 or January 31, whichever date is the first date following the end of the first calendar half after the compliance date that is specified for your source in §63.7495. (3) Each subsequent compli ance report must cover the semiannual reporting period from January 1 through June 30 or the semiannual reporting period from July 1 through December 31. (4) Each subsequent compliance report must be postmarked or delivered no later than July 31 or Januar y 31, whichever date is the first date following the end of the semiannual reporting period. (5) For each affected source that is subject to permitting regulations pursuant to 40 CFR part 70 or 40 CFR part 71, and if the permitting authority has establish ed dates for submitting semiannual reports pursuant to 40 CFR 70.6(a)(3)(iii)(A) or 40 CFR 71.6(a)(3)(iii)(A), you may271 submit the first and subsequent compliance reports according to the dates the permitting authority has established instead of according t o the dates in paragraphs (b)(1) through (4) of this section. (c) The compliance report must contain the information required in paragraphs (c)(1) through (11) of this section. (1) Company name and address. (2) Statement by a responsible official with t hat official's name, title, and signature, certifying the truth, accuracy, and completeness of the content of the report. (3) Date of report and beginning and ending dates of the reporting period. (4) The total fuel use by each affected source subject

to an emission limit, for each calendar month within the semiannual reporting period, including, but not limited to, a description of the fuel , including whether the fuel has received a non

- waste determination by you EPA or EPA your basis for concluding that t he fuel is not a waste , and the total fuel usage amount with units of measure. (5) A summary of the results of the annual performance tests and documentation of any operating limits that were reestablished during this test, if applicable. If you are cond ucting stack tests once every three years consistent272 with section 63.7515(b) or (c), the date of the last three stack tests, a comparison of the emission level you achieved in the last three stack tests to the 90 percent emission limit threshold required i n section 63.7515(b) or (c), and a statement as to whether there have been any operational changes since the last stack test that could increase emissions. (6) A signed statement indicating that you burned no new types of fuel. Or, if you did burn a new t ype of fuel, you must submit the calculation of chlorine input, using Equation 5 of §63.7530, that demonstrates that your source is still within its maximum chlorine input level established during the previous performance testing (for sources that demonstr ate compliance through performance testing) or you must submit the calculation of HCl emission rate using Equation 9 of §63.7530 that demonstrates that your source is still meeting the emission limit for HCl emissions (for boilers or process heaters that d emonstrate compliance through fuel analysis). If you burned a new type of fuel, you must submit the calculation of mercury input, using Equation 7 of §63.7530, that demonstrates that your source is still within its maximum mercury input level established during the previous performance testing (for sources that demonstrate compliance through performance273 testing), or you must submit the calculation of mercury emission rate using Equation 11 of §63.7530 that demonstrates that your source is still meeting the emission limit for mercury emissions (for boilers or process heaters that demonstrate compliance through fuel analysis). (7) If you wish to burn a new type of fuel and you can not demonstrate compliance with the maximum chlorine input operating limit usi ng Equation 5 of §63.7530 or the maximum mercury input operating limit using Equation 7 of §63.7530, you must include in the compliance report a statement indicating the intent to conduct a new performance test within 60 days of starting to burn the new fu el. (8) The hours of operation for each boiler and process heater that is subject to an emission limit for each calendar month within the semiannual reporting period. This requirement applies only to limited use boilers and process heaters. (9) If there are no deviations from any emission limits or operating limits in this subpart that apply to you, a statement that there were no deviations from the emission limits or operating limits during the reporting period. (1 0 ) If there were no deviations from the monitoring requirements including no periods during which the CMSs,274 including CEMS, COMS, and CPMS, were out of control as specified in §63.8(c)(7), a statement that there were no deviations and no periods during which the CMS were out of control during t he reporting period. (d) For each deviation from an emission limit or operating limit in this subpart that occurs at an affected source where you are not using a CMS to comply with that emission limit or operating limit, the compliance report

must additio nally contain the information required in paragraphs (d)(1) through (4) of this section. This includes periods of startup, shutdown, and malfunction. (1) The total operating time of each affected source during the reporting period. (2) A description of t he deviation and which emission limit or operating limit from which you deviated. (3) Information on the number, duration, and cause of deviations (including unknown cause), as applicable, and the corrective action taken. (4) A copy of the test report if the annual performance test showed a deviation from the emission limit s . (e) For each deviation from an emission limit , operating limit , and monitoring requirement in this subpart occurring at an affected source where you are using a CMS275 to comply with t hat emission limit or operating limit, you must include the information required in paragraphs (e) (1) through (12) of this section. This includes periods of startup, shutdown, and malfunction and any deviations from your site

- specific monitoring plan as required in §63.7505(d). (1) The date and time that each malfunction deviat ion started and stopped and description of the nature of the deviation ( i.e

. , . , what you deviated from). (2) The date and time that each CMS was inoperative, except for zero (lo w - level) and high

- level checks. (3) The date, time, and duration that each CMS was out of control, including the information in §63.8(c)(8). (4) The date and time that each deviation started and stopped, and whether each deviation occurred during a perio d of startup, shutdown, or malfunction or during another period. (5) A summary of the total duration of the deviation during the reporting period and the total duration as a percent of the total source operating time during that reporting period. (6) A n analysis of the total duration of the deviations during the reporting period into those that are due to startup, shutdown, control equipment problems,276 process problems, other known causes, and other unknown

causes. (7) A summary of the total duration of C MSs downtime during the reporting period and the total duration of CMS downtime as a percent of the total source operating time during that reporting period. (8) An identification of each parameter that was monitored at the affected source for which there was a deviation. (9) A brief description of the source for which there was a deviation. (10) A brief description of each CMS for which there was a deviation. (11) The date of the latest CMS certification or audit for the system for which there was a de viation. (12) A description of any changes in CMSs, processes, or controls since the last reporting period for the source for which there was a deviation. (f) Each affected source that has obtained a title V operating permit pursuant to 40 CFR part 70 or 40 CFR part 71 must report all deviations as defined in this subpart in the semiannual monitoring report required by 40 CFR 70.6(a)(3)(iii)(A) or 40 CFR 71.6(a)(3)(iii)(A). If an affected source submits a compliance report pursuant to277 Table 9 to this subp art along with, or as part of, the semiannual monitoring report required by 40 CFR 70.6(a)(3)(iii)(A) or 40 CFR 71.6(a)(3)(iii)(A), and the compliance report includes all required information concerning deviations from any emission limit, operating limit, or work practice requirement in this subpart, submission of the compliance report satisfies any obligation to report the same deviations in the semiannual monitoring report. However, submission of a compliance report does not otherwise affect any obligatio n the affected source may have to report deviations from permit requirements to the permit authority. ( g ) In addition to the information required in §63.9(h)(2), your notification must include the following certification(s) of compliance, as applicable, and signed by a responsible official: (i) “This facility complies with the requirements in §63. 7540(a)(10) to conduct an annual tune

- up of the unit”. (ii) “This facility has had an energy assessment performed according to §63. 7530(e) .” (iii) “No seco ndary material material s that are solid waste were combusted in any affected unit.” (h) After December 31, 2011, within 60 days after the date of completing each performance evaluation conducted to278 demonstrate compliance with this subpart, the owner or

oper ator of the affected facility must submit the test data to EPA by successfully entering the data electronically into EPA’s WebFIRE database data base through EPA’s Central Data Exchange. The owner or operator of an affected facility shall enter the test da ta into EPA’s data base using the Electronic Reporting Tool (ERT) or other compatible electronic spreadsheet. Only performance evaluation data collected using methods compatible with ERT are subject to this requirement to be submitted electronically into EPA’s WebFIRE database.
§ 63.7555 What records must I keep? (a) You must keep records according to paragraphs (a)(1) through (3) of this section. (1) A copy of each notification and report that you submitted to comply with this subpart, including all documentation supporting any Initial Notification or Notification of Compliance Status or semiannual compliance report that you submitted, according to the requirements in §63.10(b)(2)(xiv). (2) Records of performance stack tests, fuel analyses, or other compliance demonstrations, performance evaluations, and opacity observations as required in §63.10(b)(2)(viii).279 (b) For each CEMS, CPMS, and COMS, you must keep records according to paragraphs (b)(1) through (5) of this section. (1) Records described in §63.10(b)(2) (vi) through (xi). (2) Monitoring data for continuous opacity monitoring system during a performance evaluation as required in §63.6(h)(7)(i) and (ii). (3) Previous ( i.e., superseded) versions of the performance evaluation plan as required in §63.8(d)(3). (4) Request for alternatives to relative accuracy test for CEMS as required in §63.8(f)(6)(i). (5) Records of the date and time that each deviation started and stopped, and whether the deviation occurred during a period of startup, shutd own, or malfunction or during another period. (c) You must keep the records required in Table 8 to this subpart including records of all monitoring data and calculated averages for applicable operating limits such as opacity, pressure drop, and pH to show continuous compliance with each emission limit and operating limit that applies to you.280 (d) For each boiler or process heater subject to an emission limit, you must also keep the records in paragraphs (d)(1) through (5) of this section. (1) You must kee p records of monthly fuel use by each boiler or process heater, including the type(s) of fuel and amount(s) used. (2) If any of the fuels you combust received a non

waste determination under non - hazardous secondary materials that have been determined not to be solid waste pursuant to 40 CFR 241 41 .3 , (b)(1), you must keep a record which documents how the fuel secondary material meets each of the legitimacy criteria and . If you combust a fuel that has been processed from a discarded non

- hazardous secondary

m aterial pursuant to 241.3(b)(2), you must keep records as to how the operations that produced the fuel satisfies the definition of processing , if applicable, consistent with in 40 CFR 241. 3 2

. If the fuel did not remain within the control of the generator, you must keep a copy of fuel received a non

- waste determination pursuant to the petition

process submitted under 40 CFR 241.3 , and (c) , you must keep a record which documents how the fuel satisfies the non waste determination granted by EPA requirements of t he petition process

.281
( 3 ) You must keep records of monthly hours of operation by each boiler or process heater. This requirement applies only to limited

- use boilers and process heaters. ( 4 ) A copy of all calculations and supporting documentation of maximum chlorine fuel input, using Equation 5 of §63.7530, that were done to demonstrate continuous compliance with the HCl emission limit, for sources that demonstrate compliance through performance testing. For sources that demonstrate compliance through fuel a nalysis, a copy of all calculations and supporting documentation of HCl emission rates, using Equation 9 of §63.7530, that were done to demonstrate compliance with the HCl emission limit. Supporting documentation should include results of any fuel analyses and basis for the estimates of maximum chlorine fuel input or HCl emission rates. You can use the results from one fuel analysis for multiple boilers and process heaters provided they are all burning the same fuel type. However, you must calculate chlorin e fuel input, or HCl emission rate, for each boiler and process heater. ( 5 ) A copy of all calculations and supporting documentation of maximum mercury fuel input, using Equation 7 of §63.7530, that were done to demonstrate continuous compliance with the m ercury emission limit for sources that282 demonstrate compliance through performance testing. For sources that demonstrate compliance through fuel analysis, a copy of all calculations and supporting documentation of mercury emission rates, using Equation 11 o f §63.7530, that were done to demonstrate compliance with the mercury emission limit. Supporting documentation should include results of any fuel analyses and basis for the estimates of maximum mercury fuel input or mercury emission rates. You can use the results from one fuel analysis for multiple boilers and process heaters provided they are all burning the same fuel type. However, you must calculate mercury fuel input, or mercury emission rates, for each boiler and process heater. (6) If consistent with 63.7555(b) and (c), you choose to stack test less frequently than annually, you must keep annual records that document that your emissions in the previous stack test(s) were less than 90 percent of the applicable emission limit, and document that there was no change in source operations including fuel composition and operation of air pollution control equipment that would cause emissions of the relevant pollutant to increase within the past year. (7) If you operate a gaseous fuel unit that is subject to the emission limits specified in Table 1 or 2 to this283 subpart, and you intend to use a fuel other than natural gas or equivalent to fire the affected unit, you must keep records of the information required by the notification under 63.XXXX, and records of the total hours per calendar year that liquid fuel is burned. (e) If you elect to average emissions consistent with 63.7522, you must additionally keep a copy of the emission averaging implementation plan required in 63.7522(g), all calculations required unde r 63.7522, including daily records of heat input or steam generation, as applicable, and monitoring records consistent with 63.7541.
§ 63.7560 In what form and how long must I keep my records? (a) Your records must be in a form suitable and readily av ailable for expeditious review, according to §63.10(b)(1). (b) As specified in §63.10(b)(1), you must keep each record for 5 years following the date of each occurrence, measurement, maintenance, corrective action, report, or record. (c) You must keep ea ch record on site for at least 2 years after the date of each occurrence, measurement, maintenance, corrective action, report, or record,284 according to §63.10(b)(1). You can keep the records off site for the remaining 3 years. **OTHER REQUIREMENTS AND INFORMA TION**  § 63.7565 What parts of the General Provisions apply to

me? Table 10 to this subpart shows which parts of the General Provisions in §§63.1 through 63.15 apply to you.
§ 63.7570 Who implements and enforces this subpart? (a) This subpart can be im plemented and enforced by U.S. EPA, or a delegated authority such as your State, local, or tribal agency. If the EPA Administrator has delegated authority to your State, local, or tribal agency, then that agency (as well as the U.S. EPA) has the authority to implement and enforce this subpart. You should contact your EPA Regional Office to find out if this subpart is delegated to your State, local, or tribal

agency. (b) In delegating implementation and enforcement authority of this subpart to a State, lo cal, or tribal agency under 40 CFR part 63, subpart E, the authorities listed in paragraphs (b)(1) through (5) of this section are retained by the EPA Administrator and are not transferred to the State, local, or tribal agency, however, the U.S.285
EPA retain s oversight of this subpart and can take enforcement actions, as appropriate. (1) Approval of alternatives to the non

- opacity emission limits and work practice standards in §63.7500(a) and (b) under §63.6(g). (2) Approval of alternative opacity emission limits in §63.7500(a) under §63.6(h)(9). (3) Approval of major change to test methods in Table 5 to this subpart under §63.7(e)(2)(ii) and (f) and as defined in §63.90 , and alternative analytical methods requested under 63.7521(b)(2). (4) Approval of maj or change to monitoring under §63.8(f) and as defined in §63.90 , and approval of alternative operating parameters under 63.7500(a)(2) and 63.7522(g)(2)

. (5) Approval of major change to recordkeeping and reporting under §63.10( f e ) and as defined in §63.90.
§ 63.7575 What definitions apply to this subpart? Terms used in this subpart are defined in the CAA, in §63.2 (the General Provisions), and in this section as follows: Bag leak detection system means a group of instrument s that are capable of monitori ng particulate matter loadings in the exhaust of a fabric filter ( i.e. , baghouse) in order2 86 to detect bag failures. A bag leak detection system includes, but is not limited to, an instrument that operates on electrodynamic, triboelectric, light scattering, light transmittance, or other principle to monitor relative particulate matter loadings. Biomass fuel means b ut is not limited to, wood residue, and wood products ( e.g . , . , trees, tree stumps, tree limbs, bark, lumber, sawdust, sanderdust, chips,

scraps, slabs, millings, and shavings); animal litter manure, including litter other bedding materials ; vegetative agricultural and silvicultural materials, such as logging residues (slash), nut and grain hulls and chaff ( e.g . , . , almond, walnut, peanut, rice, an d wheat), bagasse, orchard prunings, corn stalks, coffee bean hulls and grounds. This definition of biomass fuel is not intended to suggest that these materials are or not solid

waste. Blast furnace gas fuel

- fired boiler or process heater means an indust rial/commercial/institutional boiler or process heater that receives 90 percent or more of its total heat input (based on an annual average) from blast furnace gas. Boiler means an enclosed device using controlled flame combustion and having the primary p urpose of recovering287 thermal energy in the form of steam or hot water. A device combusting solid waste, as defined in 40 CFR 241.3, is not a boiler. Waste heat boilers are excluded from this definition. Coal means all solid fuels classifiable as anthrac ite, bituminous, sub

- bituminous, or lignite by the American Society for Testing and Materials in ASTM D388

– 991. 1 , “Standard Specification for Classification of Coals by Rank 1 ” (incorporated by reference, see §63.14(b)), coal refuse, and petroleum coke. Synthetic fuels derived from coal for the purpose of creating useful heat including but not limited to, solvent

- refined coal, coal

- oil mixtures, and coal

- water mixtures, for the purposes of this subpart. Coal derived gases are excluded from this definitio n. Coal refuse means any by

- product of coal mining or coal cleaning operations with an ash content greater than 50 percent (by weight) and a heating value less than 13,900 kilojoules per kilogram (6,000 Btu per pound) on a dry basis. Commercial/instituti onal boiler means a boiler used in commercial establishments or institutional establishments such as medical centers, research centers, institutions of higher education, hotels, and laundries to provide electricity, steam, and/or hot water.288

Common Stack m eans the exhaust of emissions from two or more affected units through a single flue.
Cost

- effective energy conservation measure means a measure that is implemented to improve the energy efficiency of the boiler or facility that has a payback (return of in vestment) period of three or fewer years. Deviation. (1) Deviation means any instance in which an affected source subject to this subpart, or an owner or operator of such a source: (i) Fails to meet any requirement or obligation established by this su bpart 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 p ermit 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 o f the standards. Distillate oil means fuel oils, including recycled oils, that comply with the specifications for fuel oil numbers 1 and 2, as defined by the American Society for289 Testing and Materials in ASTM D396

– 02a, “Standard Specifications for Fuel Oi ls 1 ” (incorporated by reference, see §63.14(b)). Dry scrubber means an add

- on air pollution control system that injects dry alkaline sorbent (dry injection) or sprays an alkaline sorbent (spray dryer) to react with and neutralize acid gas in the exhaust stream forming a dry powder material. Sorbent injection systems in fluidized bed boilers and process heaters are included in this definition. Dutch oven means a unit having a refractory

- walled cell connected to a conventional boiler setting. Fuel materi als are introduced through an opening in the roof of the D utch oven and burn in a pile on its floor. Electric utility steam generating unit means a fossil fuel

- fired combustion unit of more than 25 megawatts that serves a generator that produces electrici ty 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 consi dered an electric utility steam generating unit.290 Electrostatic precipitator 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 c ollecting surface, and transporting the particles into a hopper. Energy a ssessment means an in

- depth assessment of a facility to identify immediate and long

- term opportunities to save energy, focusing on the steam and process heating systems which involve s a thorough examination of potential savings from energy efficiency improvements, waste minimization and pollution prevention, and productivity improvement. Equivalent means the following only as this term is used in Table 6 to subpart DDDDD: (1) An equ ivalent sample collection procedure means a published voluntary consensus standard or practice (VCS) or EPA method that includes collection of a minimum of three composite fuel samples, with each composite consisting of a minimum of three increments collec ted at approximately equal intervals over the test period. (2) An equivalent sample compositing procedure means a published VCS or EPA method to systematically mix and obtain a representative subsample (part) of the composite sample.291 (3) An equivalent sa mple preparation procedure means a published VCS or EPA method that: Clearly states that the standard, practice or method is appropriate for the pollutant and the fuel matrix; or is cited as an appropriate sample preparation standard, practice or method fo r the pollutant in the chosen VCS or EPA determinative or analytical method. (4) An equivalent procedure for determining heat content means a published VCS or EPA method to obtain gross calorific (or higher heating) value. (5) An equivalent procedure for determining fuel moisture content means a published VCS or EPA method to obtain moisture content. If the sample analysis plan calls for determining metals (especially the mercury, selenium, or arsenic) using an aliquot of the dried sample, then the drying temperature must be modified to prevent vaporizing these metals. On the other hand, if metals analysis is done on an “as received” basis, a separate aliquot can be dried to determine moisture content and the metals concentration mathematically adjusted to a dry basis. (6) An equivalent pollutant (mercury) determinative or analytical procedure means a published VCS or EPA method that clearly states that the standard, practice, or method is appropriate for the pollutant and the fuel matrix and292 has a publish ed detection limit equal or lower than the methods listed in Table 6 to subpart DDDDD for the same

purpose. Fabric filter means an add

- on air pollution control device used to capture particulate matter by filtering gas streams through filter media, also k nown as a baghouse. Federally enforceable means all limitations and conditions that are enforceable by the EPA Administrator, including the requirements of 40 CFR parts 60 and 61, requirements within any applicable State implementation plan, and any permi t requirements established under 40 CFR 52.21 or under 40 CFR 51.18 and 40 CFR 51.24. Fuel type means each category of fuels that share a common name or classification. Examples include, but are not limited to, bituminous coal, subbituminous coal, lignite , anthracite, biomass, residual oil. Individual fuel types received from different suppliers are not considered new fuel types. Fluidized Bed Boiler means a boiler utilizing a fluidized bed combustion process. Fluidized bed combustion means a proces s where a fuel is burned in a bed of granulated particles which are maintained in a mobile suspension by the forward flow of air and combustion products.293

Fuel cell means a boiler type in which the fuel is dropped onto suspended fixed grates and is fired i n a pile.

T he refractory

- lined fuel cell uses combustion air preheating and positioning of secondary and tertiary air injection ports to improve boiler efficiency. Gaseous fuel includes, but is not limited to, natural gas, process gas, landfill gas, coal derived gas, refinery gas, and biogas. Blast furnace gas is exempted from this definition. Heat input means heat derived from combustion of fuel in a boiler or process heater and does not include the heat input from preheated combustion air, recirculated flue gases, or exhaust gases from other sources such as gas turbines, internal combustion engines, 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 or liq uid fuel and is withdrawn for use external to the vessel at pressures not exceeding 160 psig, including the apparatus by which the heat is generated and all controls and devices necessary to prevent water temperatures from exceeding 210 °F (99 °C). Indust rial boiler means a boiler used in manufacturing, processing, mining, and refining or any294 other industry to provide steam, hot water, and/or electricity. Liquid fuel subcategory includes any boiler or process heater of any design that does not burn any so lid fuel and burns any liquid fuel either alone or in combination with gaseous fuels. G aseous fuel boilers and process heaters that burn liquid fuel during periods of gas curtailment, gas supply emergencies or for periodic testing of liquid fuel not to ex ceed a combined total of 48 hours during any calendar year are not included in this definition. Liquid fuel includes, but is not limited to, distillate oil, residual oil, on - spec used oil, and process liquids. Metal process furnaces include natural gas

- f ired annealing furnaces, preheat furnaces, reheat furnaces, aging furnaces, and heat treat furnaces. Minimum pressure drop means 90 percent of the test average pressure drop measured according to Table 7 to this subpart during the most recent performance test demonstrating compliance with the applicable emission limit. Minimum scrubber effluent pH means 90 percent of the test average effluent pH measured at the outlet of the wet scrubber according to Table 7 to this subpart during the295 most recent performa nce test demonstrating compliance with the applicable hydrogen chloride emission limit. Minimum scrubber flow rate means 90 percent of the test average flow rate measured according to Table 7 to this subpart during the most recent performance test demonst rating compliance with the applicable emission limit. Minimum sorbent flow rate means 90 percent of the test average sorbent (or activated carbon) flow rate measured according to Table 7 to this subpart during the most recent performance test demonstratin g compliance with the applicable emission limits. Minimum voltage or amperage means 90 percent of the test average voltage or amperage to the electrostatic precipitator measured according to Table 7 to this subpart during the most recent performance test demonstrating compliance with the applicable emission limits. Natural gas means: (1) A naturally occurring mixture of hydrocarbon and nonhydrocarbon gases found in geologic formations beneath the earth's surface, of which the principal constituent is

met hane; or (2) Liquid petroleum gas, as defined by the American Society for Testing and Materials in ASTM D1835

– 03a,296 “Standard Specification for Liquid Petroleum Gases” (incorporated by reference, see §63.14(b)). Opacity means the degree to which emissions reduce the transmission of light and obscure the view of an object in the background. Particulate matter means any finely divided solid or liquid material, other than uncombined water, as measured by the test methods specified under this subpart, or an

a lternative method. Period of natural gas curtailment or supply interruption means a period of time during which the supply of natural gas to an affected facility is halted for reasons beyond the control of the facility. An increase in the cost or unit pri ce of natural gas does not constitute a period of natural gas curtailment or supply interruption. Process heater means an enclosed device using controlled flame, that is not a boiler, and the unit's primary purpose is to transfer heat indirectly to a proc ess material (liquid, gas, or solid) or to a heat transfer material for use in a process unit, instead of generating

steam. Process heaters are devices in which the combustion gases do not directly come into contact with process materials. A device combu sting solid waste, as defined in 40 CFR 241.3, is not a process heater. Process heaters do297 not include units used for comfort heat or space heat, food preparation for on

- site consumption, or autoclaves. Pulverized coal boiler means a boiler in which pulv erized coal is introduced into an air stream that carries the coal to the combustion chamber of the boiler where it is fired in suspension. Qualified personnel mean specialists in evaluating energy systems who have successfully completed the DOE Qualified Specialist program or the equivalent. Residual oil means crude oil, and all fuel oil numbers 4, 5 and 6, as defined by the American Society for Testing and Materials in ASTM D396

– 02a, “Standard Specifications for Fuel Oils 1 ” (incorporated by reference, see §63.14(b)). Responsible official means responsible official as defined in 40 CFR 70.2. Stoker means a unit consisting of a mechanically operated fuel feeding mechanism, a stationary or moving grate to support the burning of fuel and admit undergrate

a ir to the fuel, an overfire air system to complete combustion, and an ash discharge system. There are two general types of stokers: underfeed and overfeed. Overfeed stokers include mass feed and spreader stokers. Suspension boiler means a unit designed to feed the fuel by means of fuel distributors. The distributors298 inject air at the point where the fuel is introduced into the boiler in order to spread the fuel material over the boiler width. The drying (and much of the combustion) occurs while the mat erial is suspended in air. The combustion of the fuel material is completed on a grate or floor below. Suspension boilers almost universally are designed to have high heat release rates to quickly dry the wet fuel as it is blown into the boilers. Tempor ary 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. A temporary boiler that remains at a location for more than 180 consecutive days is no longer considered to be a temporary boiler. Any temporary boiler that replaces a temporary boiler at a location and is intended to perform the same or similar function will be included in calculating the consecutive time period.

Tune

- up means adjustments made to a boiler in

acc ordance with procedures supplied by the manufacturer (or an approved specialist) to optimize the combustion efficiency. Unit designed to burn biomass subcategory includes any boiler or process heater that burns a t least 10 percent biomass, but less than 1 0 percent coal , on a heat input299 basis on an annual average , either alone or in combination with l iquid fuels or gaseous fuels. Unit designed to burn coal subcategory includes any boiler or process heater that burns at least 10 percent coal on a heat input basis on an annual average either alone or in combination with biomass, liquid fuels, or gaseous fuels. Unit designed to burn gas 1 (NG/RG) subcategory includes any boiler or process heater that burn s at least 90 percent natural gas and/or refinery gas o n a heat input basis on an annual average

. Unit designed to burn gas 2 (other) subcategory includes any boiler or process heater that burn s gaseous fuels other than natural gas and/or refinery gas not combined with any solid or liquid fuels. Unit designe d to burn oil subcategory includes any boiler or process heater that burns any liquid fuel, but less than 10 percent solid fuel on a heat input basis on an annual average, either alone or in combination with gaseous fuels. G aseous fuel boilers and process heaters that burn liquid fuel during periods of gas curtailment, gas supply emergencies or for periodic testing of liquid fuel not to exceed a combined total of 48 hours during any calendar year are not included in this definition.300 Voluntary Consensus St andards or VCS mean technical standards ( e.g. , materials specifications, test methods, sampling procedures, business practices) developed or adopted by one or more voluntary consensus bodies. EPA/OAQPS has by precedent only used VCS that are written in E nglish. Examples of VCS bodies are: American Society of Testing and Materials (ASTM), American Society of Mechanical Engineers (ASME), International Standards Organization (ISO), Standards Australia (AS), British Standards (BS), Canadian Standards (CSA), E uropean Standard (EN or CEN) and German Engineering Standards (VDI). The types of standards that are not considered VCS are standards developed by: the U.S. states, e.g. , California (CARB) and Texas (TCEQ); industry groups, such as American Petroleum Inst itute (API), Gas Processors Association (GPA), and Gas Research Institute (GRI); and other branches of the U.S. government, e.g. Department of Defense (DOD) and Department of Transportation (DOT). This does not preclude EPA from using standards developed b y groups that are not VCS bodies within their rule. When this occurs, EPA has done searches and reviews for VCS equivalent to these

non - EPA methods. Waste heat boilers boiler means a device that recovers normally unused energy and converts it to usable hea t.301

Waste heat recovery boilers incorporating duct or supplemental burners that are designed to supply 50 percent or more of the total rated heat input capacity of the waste heat boiler are not considered waste heat boilers, but are considered boilers. Wa ste heat boilers are also referred to as heat recovery steam generators. Waste heat process heater

Wet scrubber means any add

- on air pollution control device that mixes an aqueous stream or slurry with the exhaust gases from a boiler or process heater to control emissions of particulate matter and/or to absorb and

n eutralize acid gases, such as hydrogen chloride. means an enclosed device that recovers normally unused energy and converts it to usable heat. Waste heat process heaters incorporating duct or supplemental burners that are designed to supply 50 percent or more of the total rated heat input capacity of the waste heat process heater are not considered waste heat process heaters, but are considered process heaters. Waste heat process heaters are also referred to as recuperative process heaters.

Work practice standard means any design, equipment, work practice, or operational standard, or combination thereof, that is promulgated pursuant to section 112(h) of the CAA.302

**TABLES TO SUBPART DDDDD OF PART 63** 

**Table 1 to Subpart DDDDD of Part 63 —**  **Emission Limits for New**  **or Reconstructed Boilers and Process Heaters**

As stated in §63.7500, you must comply with the following appl icable emission limits : **If your boiler or process heater is**  **in this subcategory**  **... F**  **or the following pollutants . . .**  **You must meet the following emission limits and work**  **practice standards . . .**

1. Pulverized coal a. Particulate Matter 0. 0 009 0 0 1 lb per MMBtu of heat input. b. Hydrogen Chloride 0. 0 0005 0 000 6 lb per MMBtu of heat input

. c. Mercury 0.00000 07 2.0E

- 06 lb per MMBtu of heat input.

d. CO 1 90 ppm by volume on a dry basis corrected to 3 percent oxygen (30

- day rolling average for units 100 MMBtu/hr or greater, 3

- run average for units less than 100 MMBtu/hr). e. Dioxin/F uran 0.002 ng/dscm (TEQ) corrected to 7 percent oxygen. 2. Stokers designed to burn coal a. Particulate Matter 0. 0 009 0 0 1 lb per MMBtu of heat input. b. Hydrogen Chloride 0. 0 0005 0 000 6 lb per MMBtu of heat input. c. Mercury 0.00000 07 2. 0 E

- 06 lb per M MBtu of heat input.

d. CO 7 ppm by volume on a dry basis corrected to 3 percent oxygen (30

- day rolling average for units 100 MMBtu/hr or greater, 3

- run average for units less than 100 MMBtu/hr). e. Dioxin/Furan 0.003 ng/dscm (TEQ) corrected to 7 per cent oxygen. 3. Fluidized bed units designed to burn coal a. Particulate Matter 0. 0 009 0 0 1 lb per MMBtu of heat input. b. Hydrogen Chloride 0. 0 0005 0 000 6 lb per MMBtu of heat input. c. Mercury 0.00000 07 2.0E

- 06 lb per MMBtu of heat input. d. CO 40 3 0 ppm by volume on a dry Formatted Table

Formatted Table303

basis corrected to 3 percent oxygen (30

- day rolling average for units 100 MMBtu/hr or greater, 3

- run average for units less than 100 MMBtu/hr). e. Dioxin/Furan 0.00003 ng/dscm (TEQ) corrected to 7 percent oxygen. 4. Stokers desi gned to burn biomass a. Particulate Matter 0. 007 00 8 lb per MMBtu of heat input. b. Hydrogen Chloride 0. 00 06 00 4 lb per MMBtu of heat input.

c. Mercury 0.00000007 2.0E

- 07 lb per MMBtu of heat input

.

d. CO 780 560 ppm by volume on a dry basis correcte d to 3 percent oxygen (30

- day rolling average for units 100 MMBtu/hr or greater, 3

- run average for units less than 100 MMBtu/hr). e. Dioxin/Furan 0.00005 ng/dscm (TEQ) corrected to 7 percent oxygen. 5. Fluidized bed units designed to burn biomass a. Par ticulate Matter 0. 007 00 8 lb per MMBtu of heat input. b. Hydrogen Chloride 0. 00 06 00 4 lb per MMBtu of heat input.

c. Mercury 0.00000007 2.0E

- 07 lb per MMBtu of heat input

.

d. CO 40 ppm by volume on a dry basis corrected to 3 percent oxygen (30

- day r olling average for units 100 MMBtu/hr or greater, 3

- run average for units less than 100 MMBtu/hr). e. Dioxin/Furan 0.007 ng/dscm (TEQ) corrected to 7 percent oxygen. 6. Suspension burners/Dutch Ovens designed to burn biomass a. Particulate Matter 0. 007 0 0 8 lb per MMBtu of heat input.
b. Hydrogen Chloride 0. 00 06 00 4 lb per MMBtu of heat input. c. Mercury 0.00000007 2.0E

- 07 lb per MMBtu of heat input

.

d. CO 460 1,010 ppm by volume on a dry basis corrected to 3 percent oxygen (30

- day rolling average for units 100 MMBtu/hr or greater, 3

- run average for units less than 100 MMBtu/hr). Formatted Table

Formatted Table304

e. Dioxin/Furan 0.03 ng/dscm (TEQ) corrected to 7 percent oxygen. 7. Fuel cells designed to burn biomass a. Particulate Matter 0. 007 00 8 lb per MMBtu of heat input. b. Hyd rogen Chloride 0. 00 06 00 4 lb per MMBtu of heat input. c. Mercury 0.00000007 2.0E

- 07 lb per MMBtu of heat input

.

d. CO 270 ppm by volume on a dry basis corrected to 3 percent oxygen (30

- day rolling average for units 100 MMBtu/hr or greater, 3

- run average for units less than 100 MMBtu/hr). e. Dioxin/Furan 0. 0004 000 5 ng/dscm (TEQ) corrected to 7 percent oxygen. 8. Units designed to burn liquid fuel a. Particulate Matter 0.0 02 lb per MMBtu of heat input. b. Hydrogen Chloride 0. 00 01 00 0 4 lb per MMBtu of he at input. c. Mercury 0.0000003 3.0E

- 07 lb per MMBtu of heat input

.

d. CO 1 ppm by volume on a dry basis corrected to 3 percent oxygen (30

- day rolling average for units 100 MMBtu/hr or greater, 3

- run average for units less than 100 MMBtu/hr). e. Dioxin /Furan 0. 000005 00 2 ng/dscm (TEQ) corrected to 7 percent oxygen. 9

. Units designed to burn natural gas/refinery gas other gases a. Particulate Matter 0. 0004 0 03 lb per MMBtu of heat input.
b. Hydrogen Chloride 0.000 2 3.0E

- 06 lb per MMBtu of heat input.

c. Mercury 0.000000002 2.0E

- 07 lb per MMBtu of heat input

.

d. CO 20 ppm by volume on a dry basis corrected to 3 percent oxygen (30

- day rolling average for units 100 MMBtu/hr or greater, 3

- run average for units less than 100 MMBtu/hr). e. Dioxin/Furan 0.001 ng/dscm (TEQ) corrected to 7 percent oxygen. 10. Units designed to burn other gases a. Particulate Matter 0.0 02 lb per MMBtu of heat input. b. Hydrogen 0.000 003 lb per MMBtu of heat input. Formatted Table

Formatted Table305

Chloride c. Mercury 0.0000002 lb per MMBtu of heat input

.

d. CO 1 ppm by volume on a dry basis corrected to 3 percent oxygen (30

- day rolling average for units 100 MMBtu/hr or greater, 3

- run average for units less than 100 MMBtu/hr). e. Dioxin/Furan 0. 008 00 9 ng/dscm (TEQ) corrected to 7 percent oxygen. 1 1

. Metal processing furnaces a. Particulate Matter 0. 02 lb per MMBtu of heat input. b. Hydrogen Chloride 0.0002 lb per MMBtu of heat input. c. Mercury 0.0000002 lb per MMBtu of heat input

.

d. CO 2 ppm by volume on a dry basis corrected to 3 percent oxyg en (30

- day rolling average for units 100 MMBtu/hr or greater, 3

- run average for units less than 100 MMBtu/hr). e. Dioxin/Furan 0.004 ng/dscm (TEQ) corrected to 7 percent oxygen.

**Table 2**  **to Subpart DDDDD of Part 63 —**  **Emission Limits for**  **Existing Boiler s and Process**  **Heaters (**  **U nits with heat input**  **capacity of 10 million Btu per hour or greater**  **)**

As stated in §63.7500, you must comply with the following applicable emission limits:
**If your boiler or process heater is**  **in this subcategory**  **... For the followi**  **ng pollutants . . .**  **You must meet the following emission limits and work**  **practice standards . . .**

1. Pulverized coal a. Particulate Matter 0.02 lb per MMBtu of heat input. b. Hydrogen Chloride 0. 006 00 8 lb per MMBtu of heat input. c. Mercury 0.00 00 03 3.0E

- 06 lb per MMBtu of heat input.

d. CO 70 9 0 ppm by volume on a dry basis corrected to 3 percent oxygen (30

- day rolling average for units 100 MMBtu/hr or greater, 3

- run average for units less than 100 MMBtu/hr). e. Dioxin/Furan 0. 003 00 4 ng/dscm (TEQ) Formatted Table

Formatted Table306

corrected to 7 percent oxygen 2

. Stokers designed to burn coal a. Particulate Matter 0.02 lb per MMBtu of heat input

. b. Hydrogen Chloride 0. 006 00 8 lb per MMBtu of heat input. c. Mercury 0.0000 03 3.0E

- 06 lb per MMBtu of heat input.

d. C O 40 5 0 ppm by volume on a dry basis corrected to 3 percent oxygen (30

- day rolling average for units 100 MMBtu/hr or greater, 3

- run average for units less than 100 MMBtu/hr). e. Dioxin/Furan 0.003 ng/dscm (TEQ) corrected to 7 percent oxygen 3

. Fluidized bed units designed to burn coal a. Particulate Matter 0.02 lb per MMBtu of heat input. b. Hydrogen Chloride 0.00 8 lb per MMBtu of heat input. c. Mercury 3.0E

- 06 lb per MMBtu of heat input.

d. CO 3 0 ppm by volume on a dry basis corrected to 3 perc ent oxygen (30

- day rolling average for units 100 MMBtu/hr or greater, 3

- run average for units less than 100 MMBtu/hr). e. Dioxin/Furan 0.002 ng/dscm (TEQ) corrected to 7 percent oxygen 4

. Stokers designed to burn biomass a. Particulate Matter 0. 0 2 lb pe r MMBtu of heat input. b. Hydrogen Chloride 0.0 06 lb per MMBtu of heat input.

c. Mercury 9.0E

- 07 lb per MMBtu of heat input.

d. CO 560 ppm by volume on a dry basis corrected to 3 percent oxygen (30

- day rolling average for units 100 MMBtu/hr or gr eater, 3

- run average for units less than 100 MMBtu/hr). e. Dioxin/Furan 0.00 4 ng/dscm (TEQ) corrected to 7 percent oxygen. 5

. Fluidized bed units designed to burn biomass a. Particulate Matter 0. 0 2 lb per MMBtu of heat input. b. Hydrogen Chloride 0. 0 06 lb per MMBtu of heat input. Formatted Table

Formatted Table

Formatted Table307

c. Mercury 0.0000 03 9.0E

- 07 lb per MMBtu of heat input.

d. CO 40 2 5 0 ppm by volume on a dry basis corrected to 3 percent oxygen (30

- day rolling average for units 100 MMBtu/hr or greater, 3

- run average for units less than 100 MMBtu/hr). e. Dioxin/Furan 0.002 ng/dscm (TEQ) corrected to 7 percent oxygen 4

. Stokers designed to burn biomass a. Particulate Matter 0. 07 lb per MMBtu of heat input. b. Hydrogen Chloride 0.0 006 lb per MMBtu of heat input.

c. Mercury 0.000 00 07 lb per MMBtu of heat input.

d. CO 780 ppm by volume on a dry basis corrected to 3 percent oxygen (30

- day rolling average for units 100 MMBtu/hr or greater, 3

- run average for units less than 100 MMBtu/hr). e. Dioxin/Furan 0.003 ng/dscm (TEQ) correc ted to 7 percent oxygen. 5

. Fluidized bed units designed to burn biomass a. Particulate Matter 0. 07 lb per MMBtu of heat input. b. Hydrogen Chloride 0.0 006 lb per MMBtu of heat input.

c. Mercury 0.00000 07 lb per MMBtu of heat input.

d. CO 230 pp m by volume on a dry basis corrected to 3 percent oxygen (30

- day rolling average for units 100 MMBtu/hr or greater, 3

- run average for units less than 100 MMBtu/hr). e. Dioxin/Furan 0.02 ng/dscm (TEQ) corrected to 7 percent oxygen. 6

. Suspension burners/ Dutch Ovens designed to burn biomass a. Particulate Matter 0. 07 0 2 lb per MMBtu of heat input.
b. Hydrogen Chloride 0. 0 006 0 06 lb per MMBtu of heat input. c. Mercury 0.00000 07 9.0E

- 07 lb per MMBtu of heat input.

d. CO 460 1,010 ppm by volume on a dry b asis corrected to 3 percent oxygen (30

- day rolling average for units 100 MMBtu/hr or greater, 3

- run average for units less than 100 MMBtu/hr). e. Dioxin/Furan 0.03 ng/dscm (TEQ) corrected to Formatted Table

Formatted Table308

7 percent oxygen. 7

. Fuel cells designed to burn biomass a. Pa rticulate Matter 0. 07 0 2 lb per MMBtu of heat input. b. Hydrogen Chloride 0. 0 006 0 06 lb per MMBtu of heat input. c. Mercury 0.00000 07 9.0E

- 07 lb per MMBtu of heat input.

d. CO 270 ppm by volume on a dry basis corrected to 3 percent oxygen (30

- day rollin g average for units 100 MMBtu/hr or greater, 3

- run average for units less than 100 MMBtu/hr). e. Dioxin/Furan 0.02 ng/dscm (TEQ) corrected to 7 percent oxygen. 8

. Units designed to burn liquid fuel a. Particulate Matter 0.004 lb per MMBtu of heat input. b. Hydrogen Chloride 0. 0003 000 4 lb per MMBtu of heat input. c. Mercury 0.00000 8 4.0E

- 06 lb per MMBtu of heat input.

d. CO 1 ppm by volu me on a dry basis corrected to 3 percent oxygen (30

- day rolling average for units 100 MMBtu/hr or greater, 3

- run av erage for units less than 100 MMBtu/hr). e. Dioxin/Furan 0.002 ng/dscm (TEQ) corrected to 7 percent oxygen. 9

. Units designed to burn natural gas/refinery gas other gases a. Particulate Matter 0.05 lb per MMBtu of heat input. b. Hydrogen Chloride

c. Mercury 0.00000 0002 lb per MMBtu of heat input , applicable to only refinery gas

- fired units

. d. CO e. Dioxin/Furan 1 0

. Units designed to burn other gases a. Particulate Matter b. Hydrogen Chloride 0.05 3.0E

- 06 lb per MMBtu of heat input. b. Hyd rogen Chloride c. Mercury 0. 000003 2.0E

- 07 lb per MMBtu of heat input. c. Mercury 0.0000 002 lb per MMBtu of heat input. d. C0 1 ppm by volume on a dry basis Formatted Table

Formatted Table309

corrected to 3 percent oxygen (30

- day rolling average for units 100 MMBtu/hr or greater, 3

- run av erage for units less than 100 MMBtu/hr). e. Dioxin/Furan 0. 008 00 9 ng/dscm (TEQ) corrected to 7 percent oxygen.

**Table 3 to Subpart DDDDD of Part 63 —**  **Work Practice Standards**  As stated in §§63.11202 and 63.11203, you must comply with the following appl icable work practice standards: **If yo ur boiler is**  **... You must meet the following...**  1. An e xisting boiler or process heater with heat input capacity of less than 10 million Btu per hour C onduct a tune

- up of the boiler annually bie nn i ally as specified in §63. 7540

.

2. An A new or existing boiler or process heater in either the Gas 1 or Metal Process Furnace subcategory with heat input capacity of 10 million Btu per hour or greater C onduct a tune

- up of the boiler annually as specified in §63. 7540

.

3

. An e xisting boiler or process heaters located at a major source facility Must have an energy a ssessment performed on the major source facility by qualified personnel which includes: (1) a visual inspection of the boiler system. (2) establish operating ch aracteristics of the facility, energy system specifications, operating and maintenance procedures, and unusual operating constraints, (3) identify major energy consuming systems, (4) a review of available architectural and engineering plans, facility opera tion and maintenance310 procedures and logs, and fuel usage, (5) a list of major energy conservation measures, (6) the energy savings potential of the energy conservation measures identified, and (7) a comprehensive report detailing the ways to improve effici ency, the cost of specific improvements, benefits, and the time frame for recouping those investments , and (8) implement cost

- effective findings.

. 4. An existing boiler or process heater in the Gas 1 combusting refinery gas Install, operate, and maintain a carbon adsorber bed system to remove mercury from the refinery gas.

**Table 4**  **to Subpart DDDDD of Part 63 —**  **Operating Limits for Boilers and Process Heaters** 

As stated in §63.7500, you must comply with the applicable operating limits:

**If you demonstrate**  **co mpliance using** 

**. . . You must meet these operating limits . . .**  1. Wet scrubber control a. Maintain the minimum pressure drop and liquid flow

rate at or above the operating levels established during the performance test according to §63.7530(c) and Table 7 to this subpart. 2. Fabric filter control a. Install and operate a bag leak detection system according to §63.7525 and operate the fabric filter such that the bag leak detection system alarm does not sound more than 5 percent of the operating time durin g each 6

- month period; or b. This option is for boilers and process heaters that operate dry control systems. Existing and new boilers and process heaters must maintain opacity to less than or equal to 1 0 percent ( daily block average). 3. Electrostati c precipitator control a. This option is for boilers and process heaters that operate dry control systems. Existing and new boilers and process heaters must maintain opacity to less than or equal to 10 percent opacity ( daily block average); or311

b. This option is only for boilers and process heaters that operate additional wet control systems. Maintain the minimum voltage and secondary current or total power input of the electrostatic precipitator at or above the operating limits established during the pe rformance test according to §63.7530(c) and Table 7 to this subpart. 4. Dry scrubber or carbon injection control Maintain the minimum sorbent or carbon injection rate at or above the operating levels established during the performance test according to §6 3.7530(c) and Table 7 to this subpart. 5 . Any other control type This option is for boilers and process heaters that operate dry control systems. Existing and new boilers and process heaters must maintain opacity to less than or equal to 1 0 percent opacit y ( daily block average). 6. Fuel analysis Maintain the fuel type or fuel mixture such that the applicable emission rates calculated according to §63.7530(d) (3), (4) and/or(5) is less than the applicable emission limits. **Table 5 to Subpart DDDDD of Part 63 —**  **Performance Testing Requirements** 

As stated in §63.7520, you must comply with the following

requirements for performance test for existing, new or reconstructed affected sources:

**To conduct a performance test**  **for the following**

**pollutant . . . You must . .**  **. Using . . .**  1. Particulate Matter a. Select sampling ports location and the number of traverse points Method 1 in appendix A to part 60 of this chapter.

b. Determine velocity and volumetric flow

rate of the stack gas Method 2, 2F, or 2G in appendix A to part 60 of this chapter. c. Determine oxygen and carbon dioxide concentrations of the stack gas Method 3A or 3B in appendix A to part 60 of this chapter, or ASME PTC 19, Part 10 (1981) (IBR, see §63.14(i)). d. Measure the moisture content of t he stack gas Method 4 in appendix A to part 60 of this chapter.

e. Measure the particulate matter Method 5 or 17 (positive pressure fabric filters must312

emission concentration use Method 5D) in appendix A to part 60 of this chapter. f. Convert emiss ions concentration to lb per MMBtu emission rates Method 19 F

- factor methodology in appendix A to part 60 of this chapter.

2 . Hydrogen chloride a. Select sampling ports location and the number of traverse points Method 1 in appendix A to part 60 of this c hapter.

b. Determine velocity and volumetric flow

rate of the stack gas Method 2, 2F, or 2G in appendix A to part 60 of this chapter. c. Determine oxygen and carbon dioxide concentrations of the stack gas Method 3A or 3B in appendix A to part 60 of this chapter, or ASME PTC 19, Part 10 (1981) (IBR, see §63.14(i)). d. Measure the moisture content of the stack gas Method 4 in appendix A to part 60 of this chapter.

e. Measure the hydrogen chloride emission concentration Method 26 or 26A in appe ndix A to part 60 of this chapter.

f. Convert emissions concentration to lb per MMBtu emission rates Method 19 F

- factor methodology in appendix A to part 60 of this chapter.

3 . Mercury a. Select sampling ports location and the number of traverse point s Method 1 in appendix A to part 60 of this chapter.

b. Determine velocity and volumetric flow

rate of the stack gas Method 2, 2F, or 2G in appendix A to part 60 of this chapter. c. Determine oxygen and carbon dioxide concentrations of the stack ga s Method 3A or 3B in appendix A to part 60 of this chapter, or ASME PTC 19, Part 10 (1981) (IBR, see §62.14(i)). d. Measure the moisture content of the stack gas Method 4 in appendix A to part 60 of this chapter.

e. Measure the mercury emission con centration Method 29 in appendix A to part 60 of this chapter or Method 101A in appendix B to part 61 of this chapter or313

ASTM Method D6784

– 02 (IBR, see §63.14(b)). f. Convert emissions concentration to lb per MMBtu emission rates Method 19 F

- factor met hodology in appendix A to part 60 of this chapter.

4

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

b. Determine oxygen and carbon dioxide concentrations of the stack gas Method 3A or 3B in appendix A to part 60 of this chapter, or ASTM D6522

– 00 (IBR, see §63.14(b)), or ASME PTC 19, Part 10 (1981) (IBR, see §63.14(i)). c. Measure the moisture content of the stack gas Method 4 in appendix A to part 60 of this chapter.

d. Measure the CO emission concentration Method 10 in appendix A to part 60 of this chapter.

5. Dioxin/Furan a. Select the sampling ports location and the number of traverse points Method 1 in appendix A to part 60 of this chapter.

b. Determine oxygen and carbon dioxide concentrations of the stack gas Method 3A or 3B in appendix A to part 60 of this chapter, or ASTM D6522

– 00 (IBR, see §63.14(b)), or ASME PTC 19, Part 10 (1981) (IBR, see §63.14(i)). c. Measure the moisture content of the stack gas Met hod 4 in appendix A to part 60 of this chapter.

d. Measure the dioxin/furans emission concentration Method

__ in appendix A to part 60 of this chapter.

**Table 6 to Subpart DDDDD of Part 63 —**  **Fuel Analysis Requirements** 

As stated in §63.7521, you must comply with the following requirements for fuel analysis testing for existing, new or314 reconstructed affected sources. However, equivalent methods may be used in lieu of the prescribed methods at the discretion of the source owner or operator:

**To conduct**

**a fuel a**  **nalysis for the**  **following pollutant** 

***** ***** ***** **You must** ***** ***** ***** **Using** ***** ***** ***** 1. Mercury

* * * a. Collect fuel samples * * * Procedure in §63.7521(c) or ASTM D2234

– D2234M

– 03(for coal) (IBR, see §63.14(b)) or ASTM D6323

– 98 (2003) (for biomass) (IBR, See §63.14(b)) or equivalent. b. Composite fuel samples * * * Procedure in §63.7521(d) or equivalent. c. Prepare composited fuel samples * * * SW

– 846

– 3050B (for solid samples) or SW

– 846

– 3020A (for liquid samples) or ASTM D2013

– 04 (for coal) ( IBR, see §63.14(b)) or ASTM D5198

– 92 (2003) (for biomass) (IBR, see §63.14(b)) or equivalent. d. Determine heat content of the fuel type * * * ASTM D5865

– 04 (for coal) (IBR, see §63.24(b)) or ASTM E711

– 87 (for biomass) (IBR, see §63.14(b)) or equiva lent. e. Determine moisture content of the fuel type * * * ASTM D3173

– 03 (IBR, see §63.14(b)) or ASTM E871

– 82 (1998) (IBR, see §63.14(b)) or equivalent. f. Measure mercury concentration in fuel sample * * * ASTM D6722

– 01 (for coal) (IBR, see §6314(b)) or SW

– 846

– 7471A (for solid samples) or SW

– 846

– 7470A (for liquid samples or equivalent. g. Convert concentration into units of pounds of pollutant per MMBtu of heat content. 2 . Hydrogen Chloride

* * * a. Collect fuel samples * * * Proc edure in §63.7521(c) or ASTM D2234

– D2234M

– 03(for coal) (IBR, see §63.14(b)) or ASTM D6323

– 98 (2003) (for biomass) (IBR, see §63.14(b)) or equivalent. b. Composite fuel samples * * * Procedure in §63.7521(d) or equivalent. c. Prepare composited f uel samples * * * SW

– 846

– 3050B (for solid samples) or SW

– 846

– 3020A (for liquid samples)315

or ASTM D2013

– 04 (for coal) (IBR, see §63.14(b)) or ASTM D5198

– 92 (2003) (for biomass) (IBR, see §63.14(b)) or equivalent. d. Determine heat content of the fuel type * * * ASTM D5865

– 04 (for coal) (IBR, see §63.14(b)) or ASTM E711

– 87 (1996) (for biomass) (IBR, see §63.14(b)) or equivalent. e. Determine moisture content of the fuel type * * * ASTM D3173

– 03 (IBR, see §63.14(b)) or ASTM E871

– 82 (1998) or eq uivalent. f. Measure chlorine concentration in fuel sample * * * SW

– 846

– 9250 or ASTM D6721

– 01 (for coal) or ASTM E776

– 87 (1996) (for biomass) (IBR, see §63.14(b)) or equivalent. g. Convert concentrations into units of pounds of pollutant per MMB tu of heat content. [ 71 FR 70663, Dec. 6, 2006] **Table 7 to Subpart DDDDD of Part 63 —**  **Establishing Operating Limits** 

As stated in §63.7520, you must comply with the following requirements for establishing operating limits:

**If you have an**  **applicable**

**emissio n**  **limit for .**

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

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

specific minimum pressure drop and minimum flow rate operating limit according to §63.7530(c) (1) Data from the pressure drop and liquid flow rate moni tors and the particulate matter or mercury performance test (a) You must collect pressure drop and liquid flow

- rate data every 15 minutes du ring the entire period of the performance tests;

(b) Determine the average pressure drop316

and liquid flow

rate for each individual test run in the three

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

- minute readings taken during each tes t run. b. Electrostatic precipitator operating parameters (option only for units with additional wet scrubber control) i. Establish a site

specific minimum voltage and secondary current or total power input according to §63.7530(c) (1) Data from the pr essure drop and liquid flow rate monitors and the particulate matter or m ercury performance test (a) You must collect voltage and secondary current or total power input data every 15 minutes during the entire period of the performance tests;

(b) Det ermine the average voltage and secondary current or total power input for each individual test run in the three

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

- minute readings taken during each test run. 2. Hydrogen Chloride a. Wet scrubber op erating parameters i. Establish a site

specific minimum pressure drop and minimum flow rate operating limit according to §63.7530(c) (1) Data from the pH, pressure drop, and liquid flow

rate monitors and the hydrogen chloride performance test (a) You must collect pH, pressure drop, and liquid flow

rate data every 15 minutes during the entire period of the performance tests;
(b) Determine the average pH, pressure drop,317

and liquid flow

rate for each individual test run in the three

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

- minute readings taken during each test run. b. Dry scrubber operating parameters i. Establish a site

specific minimum sorbent injection rate operating limit according to §63.7530(c) (1) Data from the sorbent inje ction rate monitors and hydrogen chloride performance test (a) You must collect sorbent injection rate data every 15 minutes during the entire period of the performance tests;

(b) Determine the average sorbent injection rate for each individual test run in the three

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

- minute readings taken during each test run. **Table 8 to Subpart DDDDD of Part 63 —**  **Demonstrating Continuous Compliance** 

As stated in §63.7540, you must show continuous compliance wi th the emission limitations for affected sources according to the following:

**If you must meet the following operating**  **limits or work practice standards . . .**  **You must demonstrate continuous compliance by**

**. . .** 1. Opacity a. Collecting the opacity monitori ng system318

data according to §§63.7525(b) and 63.7535; 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 Opera tion Installing and operating a bag leak detection system according to §63.7525 and operating the fabric filter such that the requirements in §63.7540(a)(9) are met. 3. Wet Scrubber Pressure Drop and Liquid Flow

- rate a. Collecting the pressure drop and li quid flow rate monitoring system data according to §§63.7525 and 63.7535; and b. Reducing the data to 12

- hour block averages; and c. Maintaining the 12

- hour average pressure drop and liquid flow

- rate at or above the operating limits established dur ing the performance test according to §63.7530(c). 4. Wet Scrubber pH a. Collecting the pH monitoring system data according to §§63.7525 and 63.7535; and b. Reducing the data to 12

- hour block averages; and c. Maintaining the 12

- hour average pH at or above the operating limit established during the performance test according to §63.7530(c). 5. Dry Scrubber Sorbent or Carbon Injection Rate a. Collecting the sorbent or carbon injection rate monitoring system data for the dry scrubber according to §§6 3.7525 and 63.7535; and b. Reducing the data to 12

- hour block averages; and c. Maintaining the 12

- hour average sorbent or carbon injection rate at or above the operating limit established during the performance test according to §§63.7530(c). 6. E lectrostatic Precipitator Secondary Current and Voltage or Total Power Input a. Collecting the secondary current and voltage or total power input monitoring system data for the electrostatic precipitator according to §§63.7525 and 63.7535; and b. Reduc ing the data to 12

- hour block averages; and c. Maintaining the 12

- hour average secondary current and voltage or total power input at or above the operating limits established during the performance test according to319

§§63.7530(c). 7. Fuel Pollutant Con tent a. Only burning the fuel types and fuel mixtures used to demonstrate compliance with the applicable emission limit according to §63.7530(c) or (d) as applicable; and b. Keeping monthly records of fuel use according to §63.7540(a). **Table 9 to Subp art DDDDD of Part 63**  **— Reporting Requirements** 

As stated in §63.7550, you must comply with the following requirements for reports:

**You must submit a(n) The report must contain . .** 

**. You must submit**  **the report . . .** 1. Compliance report a. Information require d in §63.7550(c)(1) through (11); and Semiannually according to the requirements in §63.7550(b). b. If there are no deviations from any emission limitation (emission limit and operating limit) that applies to you and there are no deviations from the re quirements for work practice standards in Table 8 to this subpart that apply to you, a statement that there were no deviations from the emission limitations and work practice standards during the reporting period. If there were no periods during which the CMSs, including continuous emissions monitoring system, continuous opacity monitoring system, and operating parameter monitoring systems, were out

- of

- control as specified in §63.8(c)(7), a statement that there were no periods during which the CMSs were out

- of

- control during the reporting period; and c. If you have a deviation from any emission limitation320

(emission limit and operating limit) or work practice standard during the reporting period, the report must contain the information in §63.7550(d). If there were periods during which the CMSs, including continuous emissions monitoring system, continuous opacity monitoring system, and operating parameter monitoring systems, were out

- of

- control, as specified in §63.8(c)(7), the report must contain the inf ormation in §63.7550(e); and d. If you had a startup, shutdown, or malfunction during the reporting period and you took actions consistent with your startup, shutdown, and malfunction plan, the compliance report must include the information in §63.10( d)(5)(i) 2. An immediate startup, shutdown, and malfunction report if you had a startup, shutdown, or malfunction during the reporting period that is not consistent with your startup, shutdown, and malfunction plan, and the source exceeds any applicable emission limitation in the relevant emission standard a. Actions taken for the event; and i. By fax or telephone within 2 working days after starting actions inconsistent with the plan; and

b. The information in §63.10(d)(5)(ii) ii. By letter within 7 working days after the end of the event unless you have made alternative arrangements with the permitting authority.321 **Table 10 to Subpart DDDDD of Part 63 —**  **Applicability of General Provisions to Subpart DDDDD** 

As stated in §63.7565, you must comply with the applicable General Provisions according to the following:

**Citation Subject**  **Applies to subpart DDDDD**  §63.1 Applicability Yes. §63.2 Definitions Yes. Additional terms defined in §63.7575 §63.3 Units and Abbreviations Yes.

§63.4 Prohibited Activities an d Circumvention Yes.

§63.5 Preconstruction Review and Notification Requirements Yes

§63.6(a), (b)(1)

- (b)(5), (b)(7), (c), (f)(2)

- (3), (g), (h)(2)

- (h)(9), (i), (j) Compliance with Standards and Maintenance Requirements Yes.

§63.6(e)(1), (e)(3), (f)(1), and(h) (1) Startup, shutdown, and malfunction requirements and Opacity/ Visible Emission Limits No. Standards apply at all times, including during startup, shutdown, and malfunction events.

§63.7 (a), (b), (c), (d), (e)(2)

- (e)(9), (f), (g), and (h) Perform ance Testing Requirements Yes.

§63.7(e)(1) Conditions for conducting performance tests. No. Subpart DDDDD specifies conditions for conducting performance tests at §63.7520. §63.8 Monitoring Requirements Yes.322

§63.9 Notification Requirements Yes.

§ 63.10(a), (b)(1), (b)(2) (i)

- (iii) , (b)(2)(vi)(xiv), (c), (d)(1)

- (2), (e), and (f) Recordkeeping and Reporting Requirements Yes.

§63.10(b)(2)(iv)

- (v),(b)(3),and (d)(3)

- (5) No

§63.10(c)(15) Allows use of SSM plan No.

§63.11 Control Device Requirements No.

§63.12 State Authority and Delegation Yes.

§63.13

- 63.16 Addresses, Incorporation by Reference, Availability of Information, Performance Track Provisions Yes.

§63.1(a)(5),(a)(7 )

- (a)(9), (b)(2), (c)(3)

- (4), (d), 63.6(b)(6), (c)(3), (c)(4), (d), (e)( 2), (e)(3)(ii), (h)(3), (h)(5)(iv), 63.8(a)(3), 63.9(b)(3), (h)(4), 63.10(c)(2)

- (4), (c)(9). Reserved No