National Emission Standards for Hazardous Air Pollutants for Major Sources: Industrial, Commercial, and Institutional Boilers and Process Heaters

ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 63

[EPA-HQ-OAR-2002-0058; FRL-9148-5]

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 pollutants 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.

In response to the court's vacatur and remand, this action would require all major sources to meet hazardous air pollutants emissions standards reflecting the application of the maximum achievable control technology. The proposed rule would protect air quality and promote public health by reducing emissions of the hazardous air pollutants listed in section 112(b)(1) of the Clean Air Act.

We are also proposing that existing major source facilities with an affected boiler undergo an energy assessment on the boiler system to identify cost-effective energy conservation measures.

DATES:

Comments must be received on or before July 19, 2010. Under the Paperwork Reduction Act, comments on the information collection provisions are best assured of having full effect if the Office of Management and Budget (OMB) receives a copy of your comments on or before July 6, 2010.

Public Hearing.

We will hold a public hearing concerning this proposed rule and the interrelated proposed Boiler area source, CISWI, and RCRA rules, discussed in this proposal and published in the proposed rules section of today's

Federal Register

, on June 21, 2010. Persons requesting to speak at a public hearing must contact EPA by June 14, 2010.

ADDRESSES:

Submit your comments, identified by Docket ID No. EPA-HQ-OAR-2002-0058, by one of the following methods:

•

http://www.regulations.gov.

Follow the instructions for submitting comments.

•

http://www.epa.gov/oar/docket.html.

Follow the instructions for submitting comments on the EPA Air and Radiation Docket Web site.

•

E-mail:

Comments may be sent by electronic mail (e-mail) to

a-and-r-docket@epa.gov,

Attention Docket ID No. EPA-HQ-OAR-2002-0058.

•

Fax:

Fax your comments to: (202) 566-9744, Docket ID No. EPA-HQ-OAR-2002-0058.

•

Mail: Send your comments to:

EPA Docket Center (EPA/DC), Environmental Protection Agency, Mailcode: 2822T, 1200 Pennsylvania Ave., NW., Washington, DC 20460, Docket ID No. EPA-HQ-OAR-2002-0058. 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, OMB,

Attn:

Desk Officer for EPA, 725 17th St., NW., Washington, DC 20503.

•

Hand Delivery or Courier:

Deliver your comments to: EPA Docket Center, 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 should be made for deliveries of boxed information.

Instructions:

All submissions 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 online at

http://www.regulations.gov,

including any personal information provided, unless the comment includes information claimed to be confidential business information (CBI) or other information whose disclosure is restricted by statute. Do not submit information that you consider to be CBI or otherwise protected through

http://www.regulations.gov

or e-mail. The

http://www.regulations.gov

Web site is an “anonymous access” system, which means EPA will not know your identity or contact information unless you provide it in the body of your comment. If you send an e-mail comment directly to EPA without going through

http://www.regulations.gov,

your e-mail address will be automatically captured and included as part of the comment that is placed in the public docket and made available on the Internet. If you submit an electronic comment, EPA recommends that you include your name and other contact information in the body of your comment and with any disk or CD-ROM you submit. If EPA cannot read your comment due to technical difficulties and cannot contact you for clarification, EPA may not be able to consider your comment. Electronic files should avoid the use of special characters, any form of encryption, and be free of any defects or viruses.

Public Hearing:

We will hold a public hearing concerning this proposed rule on June 21, 2010. Persons interested in presenting oral testimony at the hearing should contact Ms. Pamela Garrett, Energy Strategies Group, at (919) 541-7966 by June 14, 2010. The public hearing will be held in the Washington DC area at a location and time that will be posted at the following Web site:

http://www.epa.gov/airquality/combustion.

Please refer to this Web site to confirm the date of the public hearing as well. If no one requests to speak at the public hearing by June 14, 2010 then the public hearing will be cancelled and a notification of cancellation posted on the following Web site:

http://www.epa.gov/airquality/combustion.

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 publicly available only in hard copy form. Publicly available docket materials are available either electronically in

http://www.regulations.gov

or in hard copy at the EPA Docket Center, Room 3334, 1301 Constitution 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 (202) 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 Carolina 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. When would a public hearing occur?

II. Background Information

A. What is the statutory authority for the proposed rule?

B. Summary of the Natural Resources Defense Council v. EPA Decision

C. Summary of Other Related Court Decisions

D. EPA's Response to the Vacatur

E. What is the relationship between the proposed rule and other combustion rules?

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

III. 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 startup, shutdown, and malfunction (SSM) requirements?

F. What are the testing and initial compliance requirements?

G. What are the continuous compliance requirements?

H. What are the notification, recordkeeping and reporting requirements?

I. Submission of Emissions Test Results to EPA

IV. 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. Should 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 this 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 and 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?

VI. Public Participation and Request for Comment

VII. Relationship of the Proposed Action to Section 112(c)(6) of the CAA

VIII. 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 Enforcement 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, Distribution, 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 affected 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 manufacturers.

324

Petroleum refineries, and manufacturers of coal products.

316, 326, 339

Manufacturers of rubber and miscellaneous plastic products.

331

Steel works, blast furnaces.

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 Classification System.

This table is not intended to be exhaustive, but rather provides a guide for readers regarding entities likely to be affected by this action. To determine whether your facility, company, business, organization, etc., 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, Commercial, 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).

B.

What should I consider as I prepare my comments to EPA?

Do not submit information containing CBI to EPA through

http://www.regulations.gov

or e-mail. Send or deliver information identified as CBI only to the following address: Roberto Morales, OAQPS Document Control Officer (C404-02), Office of Air Quality Planning and Standards, U.S.

Environmental Protection Agency, Research Triangle Park, North Carolina 27711, Attention: Docket ID EPA-HQ-OAR-2002-0058. Clearly 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 information that is claimed as CBI. In addition to one complete version of the comment that includes information claimed as CBI, a copy of the comment that does not contain the information claimed as CBI must be submitted for inclusion in the public docket. Information so marked will not be disclosed except in accordance with procedures set forth in 40 CFR part 2.

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 available on the World Wide Web (WWW) through the Technology Transfer Network (TTN). Following signature, a copy of the proposed action will be posted on the TTN's policy and guidance page for newly proposed or promulgated rules at the following address:

http://www.epa.gov/ttn/oarpg/.

The TTN provides information and technology exchange in various areas of air pollution control.

D. When would a public hearing occur?

We will hold a public hearing concerning this proposed rule on June 21, 2010. Persons interested in presenting oral testimony at the hearing should contact Ms. Pamela Garrett, Energy Strategies Group, at (919) 541-7966 by June 14, 2010. The public hearing will be held in the Washington, DC area at a location and time that will be posted at the following Web site:

http://www.epa.gov/airquality/combustion.

Please refer to this Web site to confirm the date of the public hearing as well. If no one requests to speak at the public hearing by June 14, 2010, then the public hearing will be cancelled and a notification of cancellation posted on the following Web site:

http://www.epa.gov/airquality/combustion.

II. Background Information

A. What is the statutory authority for this 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 sources based on the performance of the maximum achievable control technology (MACT). The MACT standards for existing sources must be at least as stringent as the average emissions limitation achieved by the best performing 12 percent of existing sources (for which the Administrator 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 consider 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 impacts when doing so.

CAA section 112(c)(6) requires EPA to list categories and subcategories of sources assuring that sources accounting for not less than 90 percent of the aggregate emissions of each such pollutant (alkylated lead compounds; polycyclic organic matter; hexachlorobenzene; mercury; polychlorinated byphenyls; 2,3,7,8-tetrachlorodibenzofurans; and 2,3,7,8-tetrachloroidibenzo-p-dioxin) are subject to standards under subsection 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,” “Industrial Wood/Wood Residue Combustion,” “Commercial Coal Combustion,” “Commercial Oil Combustion,” and “Commercial Wood/Wood Residue Combustion” are listed as source categories 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 categories included institutional fuel combustion (“1990 Emissions Inventory of Section 112(c)(6) Pollutants, Final Report,” April 1998).

CAA section 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 under the Resource Conservation and Recovery Act. Section 129(g)(6).

In

Natural Resources Defense Council

v.

EPA,

489 F. 3d 1250, 1257-61 (DC Cir. 2007), the court vacated the Commercial and Industrial Solid Waste Incineration (CISWI) Definitions Rule, 70 FR 55568 (September 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.” The 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 were 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 interpreted 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 statutory exceptions identified in [CAA section 129(g)(1).]”

NRDC

v.

EPA,

489 F.3d 1250, 1257-58.

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 (RCRA) 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 (nonhazardous 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 meaning 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).

The solid waste definitional rulemaking under RCRA is being proposed 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 industrial, commercial, or institutional boilers or process heaters combusts 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 those industrial, commercial, or institutional boilers and process heaters 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 heaters combust, including, for example, how much processing of such materials occurs, if any. We nevertheless used the information currently available to the Agency to determine which materials are solid waste and, therefore, subject to CAA section 129, and which are not solid waste and, therefore, subject to CAA section 112.

B. Summary of the Natural Resources Defense Council

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 emitting 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 acid gas HAP, 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 emissions 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 standards. In addition, we set risk-based standards, also known as health-based compliance alternatives, 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, defined the term “commercial 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 petition 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 September 22, 2005, EPA issued the CISWI Definitions Rule, which contained definitions that were substantively the same as those 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 judicial 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 Sources: Commercial and Industrial Solid Waste Incineration Units (CISWI Definitions Rule), promulgated pursuant to CAA section 129. The environmental organizations challenged the CISWI Definitions Rule on the ground that its definition of “commercial or industrial waste” was inconsistent with the plain language of CAA section 129 and therefore impermissibly constricted the class of “solid waste incineration unit[s]” that were subject to the emission standards of the CISWI Rule. The environmental groups also challenged 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, Orrville, Painesville, Shelby and St. Mary's—challenged 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 further below, the Court concluded 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 and remanded 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, the Court agreed with the environmental petitioners that EPA's definition of “commercial or industrial waste,” as incorporated in the definition of CISWI units, conflicted with the plain language of CAA section 129(g)(1). That provision defines “solid waste 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 certain types of facilities from the definition of “solid waste incineration unit,” CAA section 129 unambiguously includes 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 exclusions. The Court held that the definitions EPA promulgated in the CISWI Definitions Rule constricted the plain language of CAA section 129(g)(1), because the CISWI Definitions Rule excluded from its universe operating 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 must, therefore, be vacated, the Court also vacated the Boiler MACT because it concluded that the Boiler MACT would need to be revised because the universe of boilers subject to its standards will be different once EPA revises the CISWI definitions rule consistent with the Court's opinion. The Court did not address petitioners' specific challenges to the Boiler MACT.

C. Summary of Other Related Court Decisions

In March 2007, the DC Circuit Court issued an opinion (

Sierra Club

v.

EPA,

479 F. 3d 875 (DC Cir. 2007) (Brick MACT)) vacating and remanding CAA section 112(d) 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 achieved 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 Association, 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. Specifically, 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 resulting from the presence or absence of HAP in fuel materials 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 of performance is unintended 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 erred 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 demonstrated 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 Judge 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 cannot be achieved for other sources due to differences in local raw materials whose use is essential. (

Id.

At 884-85.9)

A second court opinion is also relevant to this proposal. In

Sierra Club

v.

EPA,

551 F. 3d 1019 (DC Cir. 2008), the 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 did not contain specific provisions covering operation during SSM operating modes; rather it referenced 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 be 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 collection was 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 CAA sections 112(d) and 129. CAA section 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 when direct monitoring of emissions is impractical * * * (G) provide such other information as the Administrator may reasonably require * * *

There were 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 the information collection effort solicited information from all potentially affected combustion units in the format of an electronic survey. The survey was submitted to the following facilities: (1) All facilities that submitted an initial notification for the 2004 boiler MACT standard, (2) all facilities identified by States as being subject to the 2004 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 part 60 subpart CCCC) and to facilities that have incineration units (e.g., energy recovery units) that were listed as exempt under the 2000 CISWI standard. Each facility was required to complete the survey for all combustion units located at the facility. The information requested for each combustion unit included the unit design, operation, air pollution control data, the fuels/materials burned, and available emissions test data, continuous emission monitoring (CEM) data, fuel/material analysis data, and permitted and regulatory emission limits.

The second component of the information collection request effort consisted of requiring the owners/operators of 169 boilers/process heaters to conduct emission testing for HAP and HAP surrogates. We first analyzed the results of the survey to determine if sufficient emissions data existed to develop emission standards under CAA sections 112(d) for all types of boilers/process heaters, all types of materials combusted, and all HAP to be regulated. If data were not sufficient, then we selected pools of candidates to conduct emission testing. We submitted a list of candidates to stakeholders, including state, industry, and environmental stakeholders, who had 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 made 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 protocols, 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, manganese, nickel, phosphorus, and selenium), carbon monoxide (CO), total hydrocarbons (THC), formaldehyde, oxides of nitrogen (NO

X

), and sulfur dioxide (SO

2

). Six facilities (two coal-fired, two biomass-fired, and two gas-fired boilers) were required to collect CEM data over 30 operating days using mobile CEM devices for CO, THC, and NO

X

. The owner/operator of each selected combustion unit was also required to collect and analyze, in accordance with acceptable procedures, the material(s) fed to the combustion 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 and are available in the docket and can be

downloaded at

http://www.epa.gov/ttn/atw/boiler/boilerpg.html.

When we compared information on boilers and process heaters from facilities submitting initial notifications 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 Boiler MACT (i.e., synthetic area source), and some units have switched out older solid 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 revised the population of combustion units subject to CAA section 129 (because they combust solid waste) and the population of boilers and process heaters 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 revised standards for incineration units covered by CAA section 129. Specifically, the data provide the Agency with updated information on the number of potentially affected units, available emission test data, and fuel/material analysis data to address variability. We are using all of the information before the Administrator to calculate the MACT floors, set emission limits, and evaluate the emission impacts of various regulatory options for these revised rulemakings.

E. What is the relationship between this 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 are 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 standards.

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 those standards in 1999 and 2006. The NSPS regulates emissions of PM, SO

2

, and NO

X

from boilers constructed after June 19, 1984. Sources subject to the NSPS will be subject to 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 considered the monitoring requirements, testing requirements, and recordkeeping requirements of the NSPS to avoid duplicating requirements.

This 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 these proposed standards 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 section 129. A rulemaking under CAA section 129 is being proposed 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 regulation under this 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?

This 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 by industrial, commercial, and institutional (ICI) boilers, accounting for 61 percent of the total HAP emissions.

1

ICI boilers and process heaters also emit lesser amounts of hydrogen fluoride, accounting for about 17 percent of total HAP emissions, and metals (arsenic, cadmium, chromium, mercury, manganese, nickel, and lead) accounting for about 6 percent of total HAP emissions. Organic HAP (formaldehyde, POM, acetaldehyde, benzene) account for about 15 percent of total HAP emissions. Exposure to these HAP, depending on exposure duration and levels of exposures, can be associated with a variety of adverse health effects. These adverse health effects may include, for example, irritation of the lung, skin, and mucus membranes, effects on the central nervous system, damage to the kidneys, and alimentary effects such as nausea and vomiting. We have classified two of the HAP as human 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 facilities. However, to the extent the adverse effects do occur, this proposed rule would reduce emissions and subsequent exposures.

1

See

Memorandum “Methodology for Estimating Impacts from Industrial, Commercial, Institutional Boilers and Process Heaters at Major Sources of Hazardous Air Pollutant Emissions” located in the docket.

III. Summary of This Proposed Rule

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 this proposed rule?

This proposed rule affects industrial boilers, institutional boilers, commercial boilers, and process heaters. In this proposed rule, process heaters 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 primary 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 boilers or process heaters within a subcategory located at a major source facility that do not combust solid waste or (2) each new or reconstructed industrial, commercial, or institutional boiler or process heater located at a major source facility that do not combust solid waste, as that term is defined by the Administrator under RCRA.

The 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.

C. Does this proposed rule apply to me?

This proposed rule applies to you if you own 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 common 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 the 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 if your new or existing boiler or process heater burns at least 10 percent coal on an annual average heat input

2

basis, the unit is in one of the coal subcategories. If your new or existing boiler or process heater burns at least 10 percent biomass, on an annual average heat input basis, and less than 10 percent coal, on an annual average heat input basis, we are proposing that the unit is in one of the biomass subcategories. If your new or existing boiler or process heater burns at least 10 percent liquid fuel (such as distillate oil, residual oil), and less than 10 percent solid fuel, on an annual heat input basis, we are proposing that the unit is in the liquid subcategory. If your new or existing boiler or process heater burns gaseous fuel and less than 10 percent, on an annual average heat input basis, of liquid or solid fuel, we are proposing that the unit is in one of the gas subcategories.

2

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).

Table 1—Emission Limits for Boilers and Process Heaters

[Pounds per million British thermal units]

Subcategory

Particulate

matter

(PM)

Hydrogen

chloride

(HCl)

Mercury

(Hg)

Carbon

monoxide (CO)

(ppm @3% oxygen)

Dioxins/

furans

(total TEQ)

(ng/dscm)

Existing—Coal Stoker

0.02

0.02

0.000003

50

0.003

Existing—Coal Fluidized Bed

0.02

0.02

0.000003

30

0.002

Existing—Pulverized Coal

0.02

0.02

0.000003

90

0.004

Existing—Biomass Stoker

0.02

0.006

0.0000009

560

0.004

Existing—Biomass Fluidized Bed

0.02

0.006

0.0000009

250

0.02

Existing—Biomass Suspension Burner/Dutch Oven

0.02

0.006

0.0000009

1010

0.03

Existing—Biomass Fuel Cells

0.02

0.006

0.0000009

270

0.02

Existing—Liquid

0.004

0.0009

0.000004

1

0.002

Existing—Gas (Other Process Gases)

0.05

0.000003

0.0000002

1

0.009

New—Coal Stoker

0.001

0.00006

0.000002

7

0.003

New—Coal Fluidized Bed

0.001

0.00006

0.000002

30

0.00003

New—Pulverized Coal

0.001

0.00006

0.000002

90

0.002

New—Biomass Stoker

0.008

0.004

0.0000002

560

0.00005

New—Biomass Fluidized Bed

0.008

0.004

0.0000002

40

0.007

New—Biomass Suspension Burner/Dutch Oven

0.008

0.004

0.0000002

1010

0.03

New—Biomass Fuel Cells

0.008

0.004

0.0000002

270

0.0005

New—Liquid

0.002

0.0004

0.0000003

1

0.002

New—Gas (Other Process Gases)

0.003

0.000003

0.0000002

1

0.009

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 thermal units (Btu) per hour or greater. Pursuant to CAA section 112(h), we are proposing a work practice standard for three particular classes of boilers and process heaters: Existing units that have a designed heat input capacity of less than 10 million Btu per hour and new and existing units in the Gas 1 (natural gas/refinery gas) subcategory and in the metal process furnaces subcategory. The work practice standard being proposed for these boilers and process heaters would require the implementation of a tune-up program as described in section III.F of this preamble.

We are also proposing a beyond-the-floor standard for all existing major source facilities having affected boilers or process heaters that would require the performance of a one-time energy assessment, as described in section III.F of this preamble, by qualified personnel, on the affected boilers and facility to identify any cost-effective energy conservation measures.

E. What are the startup, shutdown, and malfunction (SSM) requirements?

The United States Court of Appeals for the District of Columbia Circuit vacated portions of two provisions in EPA's CAA Section 112 regulations governing the emissions of HAP during periods of startup, shutdown, and malfunction (SSM).

Sierra Club

v.

EPA,

551 F.3d 1019 (DC Cir. 2008),

cert. denied, 2010 U.S. LEXIS 2265 (2010)

. Specifically, the Court vacated the SSM exemption contained in 40 CFR 63.6(f)(1) and 40 CFR 63.6(h)(1), that are part of a regulation, commonly referred to as the “General Provisions Rule,” that EPA promulgated 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 standard during periods of SSM.

Consistent with

Sierra Club

v.

EPA,

EPA has established standards in this rule that apply at all times. EPA has attempted to ensure that we have not incorporated into proposed regulatory language any provisions that are inappropriate, unnecessary, or redundant in the absence of an SSM exemption. We are specifically seeking comment on whether there are any such provisions that we have inadvertently incorporated or overlooked. We also request comment on whether there are additional provisions that should be added to regulatory text in light of the absence of an SSM exemption and provisions related to the SSM exemption (such as the SSM plan requirement and SSM recordkeeping and reporting provisions).

In establishing the standards in this rule, EPA has taken into account startup and shutdown periods and, for the

reasons explained below, has not established different standards for those periods. The standards that we are proposing are daily or monthly averages. Continuous emission monitoring data obtained from best performing units, and used in establishing the standards, include periods of startup and shutdown. Boilers, especially solid fuel-fired boilers, do not normally startup and shutdown more the once per day. Thus, we are not establishing a separate emission standard for these periods because startup and shutdown are part of their routine 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 operation. We have evaluated whether it is appropriate to have the same standards apply during startup and shutdown as applied to normal operations.

Periods of startup, normal operations, and shutdown are all predictable and routine aspects of a source's operations. However, by contrast, malfunction is defined as a “sudden, infrequent, and not reasonably preventable failure of air pollution control and monitoring equipment, process equipment or a process to operate in a normal or usual manner * * *” (40 CFR 63.2). EPA has determined that malfunctions should not be viewed as a distinct operating mode and, therefore, any emissions that occur at such times do not need to be factored into development of CAA section 112(d) standards, which, once promulgated, apply at all times. It is reasonable to interpret section 112(d) as not requiring EPA to account for malfunctions in setting emissions standards. For example, we note that Section 112 uses the concept of “best performing” sources in defining MACT, the level of stringency that major source standards must meet. Applying the concept of “best performing” to a source that is malfunctioning presents significant difficulties. The goal of best performing sources is to operate in such a way as to avoid malfunctions of their units.

Moreover, even if malfunctions were considered a distinct operating mode, we believe it would be impracticable to take malfunctions into account in setting CAA section 112(d) standards for major source boilers and process heaters. As noted above, by definition, malfunctions are sudden and unexpected events and it would be difficult to set a standard that takes into account the myriad different types of malfunctions that can occur across all sources in the category. Moreover, malfunctions can vary in frequency, degree, and duration, further complicating standard setting.

In the event that a source fails to comply with the applicable CAA section 112(d) standards as a result of a malfunction event, EPA would determine an appropriate response based on, among other things, the good faith efforts of the source to minimize emissions during malfunction periods, including preventative and corrective actions, as well as root cause analyses to ascertain and rectify excess emissions. EPA would also consider whether the source's failure to comply with the CAA section 112(d) standard was, in fact, “sudden, infrequent, not reasonably preventable” and was not instead “caused in part by poor maintenance or careless operation.” 40 CFR 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 all 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 Method).

(3) Conduct initial and annual stack tests to determine compliance with the HCl emission limits using EPA Method 26A or EPA Method 26 (if no entrained water droplets in the sample).

(4) Use EPA Method 19 to convert measured concentration values to pound per million Btu values.

(5) Conduct initial and annual test to determine compliance with the CO emission limits using either EPA Method 10 or a CO CEMS.

(6) Conduct initial and annual test to determine compliance with the D/F emission limits using 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 emission limits. You would calculate the average parameter values measured during each test run over the three run performance test. The average of the three 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 following is a summary of the operating limits that we are proposing to be established for the various types of the following units:

(1) For 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) 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 averages establishes your minimum site-specific pressure drop and liquid flow rate operating levels. If different 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 required to measure the sorbent injection rate for each sorbent used during the performance tests for HCl, mercury, and D/F and calculate the average for each sorbent for each test run. The average of the three test run averages established during the performance tests would be your site-specific minimum sorbent injection rate operating limit. If different sorbents and/or injection rates are used during the mercury, HCl, and D/F tests, the average value for each sorbent becomes your site-specific operating limit.

(4) For boilers and process 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 wet scrubber during the HCl performance test and you must measure the voltage and current of the ESP collection fields during the mercury and PM performance test. You would then be required to calculate the average value of these parameters for each test run. 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.

(6) For boilers and process heaters that choose to demonstrate compliance with the mercury emission limit on the basis of fuel analysis, you would be required 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, you would be required to measure the chlorine content of the inlet fuel that was 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 boilers or process heaters of any size which combust natural gas or refinery gas, as discussed in section IV.D.3 of this preamble. Instead, we are proposing that owners or operators of such boilers and process heaters submit to the delegated authority or EPA, as appropriate, if requested, documentation that a tune-up meeting 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 components of the burner as necessary,

(2) Inspect the flame pattern and make any adjustments to the burner necessary to optimize the flame pattern consistent with the manufacturer's specifications,

(3) Inspect the system controlling the air-to-fuel ratio, and ensure that it is correctly calibrated and functioning properly,

(4) 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 adjustments 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 be required 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 indentified. The procedures for an energy assessment 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.

G. What are the continuous compliance requirements?

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 10 percent (daily average) for existing and new units with applicable emission limits. Or, if the unit is controlled with a fabric filter, instead of continuous monitoring of opacity, the fabric filter must be continuously 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 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 and operated 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-hour block averages at or above the operating limits established during the performance test. You must monitor the pH of the scrubber and maintain the 12-hour block average at or above the operating limit established during the performance test to demonstrate continuous compliance with the HCl emission limits.

(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 the 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 proposing 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 maintained at or below your maximum fuel mercury content operating 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 proposing that you continuously monitor CO and maintain the average CO emissions at or below the applicable limit listed in Tables 1 or 2 of this proposed rule.

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

H. What are the notification, recordkeeping and reporting requirements?

All new and existing sources would be required to comply with certain requirements of the General Provisions (40 CFR part 63, subpart A), which are identified in Table 10 of this proposed rule. The General Provisions include specific requirements for notifications, recordkeeping, and reporting.

Each owner or operator would be required to submit a notification of compliance status report, as required by § 63.9(h) of the General Provisions. This proposed rule would require the owner or operator to include in the notification of compliance status report certifications of compliance with rule requirements.

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 the rule occurred, or any process changes occurred and compliance certifications were reevaluated.

This proposed rule would require records to demonstrate compliance with each emission limit and work practice standard. These recordkeeping requirements are specified directly in the General Provisions to 40 CFR part 63, and are identified in Table 10. Owners or operators 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 would be required.

We are proposing that you must keep the following records:

(1) All reports and notifications submitted to comply with this proposed rule.

(2) Continuous monitoring data as required in this proposed rule.

(3) Each instance in which you did not meet each emission limit and each operating limit (i.e., deviations from this proposed rule).

(4) Daily hours of operation by each source.

(5) Total fuel use by each affected source electing to comply with an emission limit based on fuel analysis 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 this proposed rule, for each affected source with an applicable HCl emission limit.

(7) Calculations and supporting information of mercury fuel input, as required in this proposed rule, for each affected source with an applicable mercury emission limit.

(8) A signed statement, as required in this proposed rule, indicating that you burned no new fuel type and no new fuel mixture or that the recalculation of chlorine input demonstrated that the new fuel or new mixture still meets chlorine fuel input levels, for each affected source with an applicable HCl emission limit.

(9) A signed statement, as required in this proposed rule, indicating that you burned no new fuels and no new fuel mixture or that the recalculation of mercury fuel input demonstrated 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.

(10) A copy of the results of all performance tests, fuel analysis, opacity observations, performance evaluations, or other compliance demonstrations conducted to demonstrate initial or continuous compliance with this proposed rule.

(11) A copy of your site-specific monitoring plan developed for this proposed rule as specified in 63 CFR 63.8(e), if applicable.

We are also proposing to require that you submit the following 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 subpart.

(3) Notification of Intent to conduct performance tests and/or compliance demonstration at least 60 calendar days before the performance test and/or compliance demonstration is scheduled.

(4) Notification of Compliance Status 60 calendar days following 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 129 standards, as well as for many other purposes including compliance determinations, emissions factor development, and annual emissions rate determinations. In conducting these required reviews, we have found it ineffective and time consuming not only for us but also for regulatory agencies and source owners and operators to locate, collect, and submit emissions test data because of varied locations for data storage and varied data storage methods. One improvement that has occurred in recent years is the availability of stack test reports in electronic format as a replacement for cumbersome paper copies.

In this action, we are taking a step to improve data accessibility. Owners and operators of boilers and process heaters will be required to submit to an EPA electronic database an electronic copy of reports of certain performance tests required under this rule. Data entry will be through an electronic emissions test report structure called the Electronic Reporting Tool (ERT) that will be used by the EPA 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 electronically and offices within State and local agencies which perform field test assessments. The ERT is currently available, and access to direct data submittal to EPA's electronic emissions database (WebFIRE) will become available by December 31, 2011.

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. The Web site listed at the end of this section 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. The information to be reported is already required for the existing 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 reported 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 activities 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 letters). 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 benefit 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 data will improve greatly the overall quality of the existing and new emissions factors 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 industry 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 and incorporating data for most performance tests will ensure that emissions factors, when updated, 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.

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

http://www.epa.gov/ttn/chief/ert/ert_tool.html.

IV. Rationale for This Proposed Rule

A. How did EPA determine which sources would be regulated under this proposed rule?

This 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. Therefore, we are excluding from this 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 reviewed separately by EPA. Consequently, this 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.

The scope of the process heater source category is limited to only indirect-fired units.

3

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 part 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 source categories of industrial boilers and commercial/institutional boilers for purposes of developing emission standards.

3

Indirect-fired process heaters are combustion devices in which the combustion gases do not directly come into contact with process materials.

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. Such hot water heaters, by their design and operation, could be considered boilers since hot water heaters meet the definition of a boiler as specified in the proposed rule, because they are enclosed devices that combust fuel for the purpose of recovery 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 major sources, and compared to boilers that are used for industrial, commercial, or institutional purposes. However, the primary reason that we are excluding hot water heaters is that hot water heaters are not part of the listed source category. Consequently, we are including a definition of hot water heaters that includes fuel, size, pressure and temperature limitations that we believe are appropriate to distinguish between residential-type units and industrial, commercial, or institutional 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 significant 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 specified is fired. While many boilers in the population data base 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 fuel 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 fuel 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 process 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 dependent 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 results to determine if subcategorization by unit design type was warranted. We concluded that the data were sufficient for determining that a distinguishable difference in performance exists based on unit design type. Therefore, because different types of units have different emission characteristics which may influence the feasibility of effectiveness of emission control, they should be regulated separately (

i.e.,

subcategorized). Accordingly, we 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 five basic unit types as subcategories. These are the following: (1) Units designed 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 there are different designs and combustion systems that, while having a minor effect on fuel-related HAP emissions, 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 11 subcategories for organic HAP:

Pulverized coal units,

Stokers designed to burn coal,

Fluidized bed units designed to burn coal,

Stokers designed to burn biomass,

Fluidized bed units designed 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 gas,

Units designed to burn other gases, and

Metal process furnaces.

These subcategories 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. However, 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 and 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 at least 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 at least 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 at least 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 at least 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 process heaters that are designed and operated differently compared to typical process heaters. A review of information gathered on process heaters used in the metal processing industries shows that these process heaters typically are designed with multiple burners that fire into individual combustion chambers. These individual burners are operated to cycle on and off to maintain the proper temperatures throughout the various 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. This results in emissions characteristics different from the process heaters used 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 propose to identify 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.

4

4

See

Memorandum “Development of Baseline Emission Factors for Boilers and Process Heaters at Commercial, Industrial, and Institutional Facilities” located in the docket.

B. How did EPA select the format for this proposed rule?

This proposed rule includes numerical emission limits for PM, mercury, HCl, CO, and D/F. The selection of numerical emission limits as the format for this proposed rule

provides flexibility for the regulated community by allowing a regulated source to choose any control technology or technique to meet the emission limits, rather than requiring each unit to use a prescribed control method that may not 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 boiler regulations

5

and allows easy comparison between such requirements. Additionally, this 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 mass basis.

5

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.

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.

Boilers and process heaters can emit a wide variety of compounds, depending on the fuel burned. Because of the large number of HAP potentially present and the disparity in the quantity and quality of the emissions information available, EPA grouped the HAP into five categories: Mercury, non-mercury metallic HAP, inorganic HAP, non-dioxin organic HAP, and D/F. The 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 mercury 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. For 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 fly-ash PM will control non-mercury metallic HAP. PM 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 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 applicable for units equipped with wet scrubbers which will likely be 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 scrubbers, 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 non-metallic inorganic HAP, EPA is proposing using HCl as a surrogate. The emissions test information available to EPA indicate that the primary non-metallic inorganic HAP emitted from boilers and process heaters are acid gases, with HCl present in the largest amounts. Other inorganic compounds emitted are found in much smaller quantities. Control technologies that reduce HCl also control other inorganic compounds such as chlorine and other acid gases. Thus, the best controls for HCl would also be the best controls for other inorganic HAP that are acid gases. 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 CO 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 concerns that CO may not be an appropriate surrogate for D/F because, unlike other organic HAP, D/F can be formed outside the combustion unit, we are proposing to use CO as a surrogate for non-dioxin organic HAP. We are also proposing separate emission limits for D/F. For non-dioxin organic HAP, using CO as a surrogate is a reasonable approach because minimizing CO emissions will result in minimizing non-dioxin organic HAP. Methods used for the control of non-dioxin organic HAP emissions would be the same methods used to control CO emissions. 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 volatile organic compounds (VOC) emissions). Establishing emission limits for specific organic HAP (with the exception of D/F) would be impractical and costly. CO, 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 associated with CO emissions will vary from unit to unit. For example, the principal organic HAP emitted from coal-fired units is benzene, which accounts for about 20 percent of the organic HAP while the principal organic HAP emitted from biomass-fired units is formaldehyde, which accounts for 34 percent of the organic HAP.

6

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

6

Based on emission factors reported on EPA webpage “AP 42, Fifth Edition, Volume 1—Chapter 1: External Combustion Sources” located at

http://www.epa.gov/ttn/chief/ap42/ch01/index.html.

THC could also be an appropriate surrogate for non-dioxin organic HAP because low THC also ensures good combustion efficiency and, thus, low organic HAP. However, we 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.

C. How did EPA determine the proposed emission limitations for existing 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, and 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-the-floor controls).

D. How did EPA determine the MACT floors for existing units?

EPA must consider available emissions information to determine the MACT floors. For each pollutant, we calculated the MACT floor for a subcategory of sources by ranking all the available emissions data 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.

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 switching 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 considered 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 based 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 emission factors reported in EPA's Technology Transfer Network, we determined that while fuel switching from solid fuels to gaseous or liquid fuels would decrease PM and some metals emissions, emissions of some organic HAP (

e,g.,

formaldehyde) would increase.

7

This determination is discussed in the memorandum “Development of Fuel Switching Costs and Emission Reductions for Industrial, Commercial, and Institutional Boilers and Process Heaters National Emission Standards for Hazardous Air Pollutants” located in the docket.

7

See

EPA webpage “AP 42, Fifth Edition, Volume 1—Chapter 1: External Combustion Sources” located at

http://www.epa.gov/ttn/chief/ap42/ch01/index.html.

A similar determination was made when considering fuel switching to cleaner fuels within a subcategory. 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 low 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 result 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 types. Natural gas pipelines are not available 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 natural 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 process 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. Therefore, 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.

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 are 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 process 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 appropriate criteria for identifying the MACT floor emission levels for units in the boilers and process heaters category.

Therefore, the MACT floor limits for each of the HAP and HAP surrogates (PM, mercury, CO, HCl, and D/F) are calculated based on the performance of the lowest emitting (best performing) sources in each of the subcategories. We ranked all of the sources for which we had data based on their emissions and identified the lowest emitting 12 percent of the sources for each HAP.

We 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-performing sources and in setting MACT floors.

See Mossville Envt'l Action Now

v.

EPA,

370 F.3d 1232, 1241-42 (DC Cir 2004) (holding EPA may consider emission variability in estimating performance achieved by best-performing sources and may set the floor at level that best-performing source can expect to meet “every day and under all operating conditions”).

In determining the MACT floor limits, we first determine the floor, which is the level achieved in practice by the average of the top 12 percent. We then 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 were able to replicate the compliance tests in our

data base. Specifically, the MACT floor limit is an upper prediction limit (UPL) calculated with the Student's t-test using the TINV function in Microsoft Excel. The Student's t-test has also been used in other EPA rulemakings (

e.g.,

NSPS for Hospital/Medical/Infectious Waste Incinerators) 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 observation 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 definition, the UPL represents the value which we can expect the mean of 3 future observations (3-run average) to fall below, based upon the results of an independent sample from the same population. In other words, if we were to randomly select a future test condition from any of these sources (

i.e.,

average of 3 runs), we can be 99% confident that the reported level will fall at or below the UPL value. To calculate the UPL, we used the average (or sample mean) and sample standard deviation, which are two statistical measures calculated from the sample data. The average is the central value of a data set, and the 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 to 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 degree 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 kurtosis statistic that is greater (less) than 0 indicates a relatively peaked (flat) distribution. 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 hypothesis 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 the skewness and kurtosis hypothesis tests to both the reported test values and the lognormal values of the reported test values. If the skewness (S) and kurtosis (K) statistics of the reported data set were both less than twice the SES and SEK, respectively, the dataset was classified as normally distributed. If neither of the skewness (S) and kurtosis (K) statistics, or only one of these statistics were less than twice 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 distribution 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 distributed 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, we also chose the normal distribution to be conservative. We believe this approach is more accurate and obtained more representative results than a more simplistic normal distribution assumption.

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

EP04JN10.002

Where:

n = the number of test runs

m = the number 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%) × TINV(2 × probability, n-1 degrees of freedom)*SQRT((1/n)+(

1/3

))], for a one-tailed t-value (with 2 × 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 Top 12%) × TINV(2 × probability, n-1 degrees of freedom)* SQRT((1/n)+(

1/3

))]}, for a one-tailed t-value (with 2 × probability), probability of 0.01, and sample size of n

Test method measurement imprecision can also be a component of data variability. At very low emissions levels as encountered in the data used to support this rule, the inherent imprecision in the pollutant measurement method has a large influence on the reliability of the data underlying the regulatory floor or beyond-the-floor emissions limit. Of particular concern are those data that are reported near or below a test method's pollutant detection capability. In our guidance for reporting pollutant emissions used to support this rule, we specified the criteria for determining test-specific method detection levels. Those criteria insure that there is about a 1 percent probability of an error in deciding that the pollutant measured at the method detection level is present when in fact it was absent. Such a probability is also called a false positive or the alpha, Type I, error. Another view of this probability is that one is 99 percent certain of the presence of the pollutant measured at the method detection level. Because of matrix effects, laboratory techniques, sample size, and other factors, method detection levels normally vary from test to test. We requested sources to identify (i.e., flag) data which were measured below the method detection level and to report those values as equal to the test-specific method detection level.

Variability of data due to measurement imprecision is inherently and reasonably addressed in calculating the floor emissions limit when the data base represents multiple tests for which all of the data are measured significantly above the method detection level. That is less true when the data base includes emissions occurring below method detection capabilities and are reported as the method detection level values. The data base is then truncated at the lower end of the measurement range (i.e., no values reported below the method detection level) and we believe that a floor emissions limit based on a truncated data base or otherwise including values at or near the method detection level may not adequately account for data measurement variability. We did not adjust the calculated floor for the data used for this proposal; although, we believe that accounting for measurement imprecision should be an important

consideration in calculating the floor emissions limit. We request comment on approaches suitable to account for measurement variability in establishing the floor emissions limit when based on measurements at or near the method detection level.

As noted above, the confidence level that a value measured at the detection level is greater than zero is about 99 percent. The expected measurement imprecision for an emissions value occurring at or near the method detection level is about 40 to 50 percent. Pollutant measurement imprecision decreases to a consistent relative 10 to 15 percent for values measured at a level about three times the method detection level.

8

One approach that we believe could be applied to account for measurement variability would require defining a method detection level that is representative of the data used in establishing the floor emissions limits and also minimizes the influence of an outlier test-specific method detection level value. The first step in this approach would be to identify the highest test-specific method detection level reported in a data set that is also equal to or less than the floor emissions limit calculated for the data set. This approach has the advantage of relying on the data collected to develop the floor emissions limit while to some degree minimizing the effect of a test(s) with an inordinately high method detection level (

e.g.,

the sample volume was too small, the laboratory technique was insufficiently sensitive, or the procedure for determining the detection level was other than that specified).

8

American Society of Mechanical Engineers,

Reference Method Accuracy and Precision (ReMAP): Phase 1, Precision of Manual Stack Emission Measurements,

CRTD Vol. 60, February 2001.

The second step would be to determine the value equal to three times the representative method detection level and compare it to the calculated floor emissions limit. If three times the representative method detection level were less than the calculated floor emissions limit, we would conclude that measurement variability is adequately addressed and we would not adjust the calculated floor emissions limit. If, on the other hand, the value equal to three times the representative method detection level were greater than the calculated floor emissions limit, we would conclude that the calculated floor emissions limit does not account entirely for measurement variability. We then would use the value equal to three times the method detection level in place of the calculated floor emissions limit to ensure that the floor emissions limit accounts for measurement variability. We request comment on this approach.

We are requesting comment on whether there is a more appropriate statistical approach 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 that 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 fuel-related HAP concentrations (nine individual samples collected over a 30-day period) obtained, pursuant 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.

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 straightforward 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.

We 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 indicators of performance over 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. We decided that the most accurate method available to us to determine long term fuel-related HAP emissions performance was to use data on the fuel-related HAP inputs in the fuels used by the best performing units, obtained as part of our information collection effort under the authority of CAA section 114, on long-term fuel-related HAP concentrations (nine individual samples collected over a 30-day period) in each fuel, along with the fuel-related HAP concentrations during the stack tests.

As previously discussed 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 performing 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 units 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 calculated the MACT floor based on the UPL (upper 99th percentile) as described earlier from the average performance of the best performing units, Students t-factor, and the variability of the best performing units.

This approach reasonably ensures that the emission limit selected as the MACT floor adequately represents the level of emissions actually 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 (2010) for the Industrial, Commercial, and Institutional Boilers and Process Heaters National Emission Standards for Hazardous Air Pollutants—Major Source” in the docket.

1. Determination of MACT for the Fuel-Related HAP

In developing the proposed MACT floor for the fuel-related HAP (non-mercury metals, acid gases, and mercury), as 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 presents the number of units in each of the five subcategories, along with the

number of units from which we have collected emission data. Table 2 also presents 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 12 percent, and the MACT floor (99 percent UPL 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 for Existing Subcategories

Subcategory

Parameter

PM

Mercury

HCl

Units designed for Coal firing

No. of sources in subcategory

578

578

578

No. of sources with data

366

285

318

No. in MACT floor

44

35

39

Avg of top 12%, lb/MMBtu

7.24E-03

5.95E-07

4.23E-03

99% UPL of top 12% (test runs), lb/MMBtu

0.0179

1.64E-06

7.38E-03

99% UPL with fuel variability of top 12%, lb/MMBtu

2.88E-06

1.11E-02

Units designed for Biomass firing

No. of sources in subcategory

420

420

420

No. of sources with data

192

91

92

No. in MACT floor

24

11

12

Avg of top 12%, lb/MMBtu

6.06E-03

3.46E-07

4.34E-03

99% UPL of top 12% (test runs), lb/MMBtu

0.0162

7.52E-07

6.00E-03

99% UPL with fuel variability of top 12%, lb/MMBtu

8.88E-07

Units designed for Liquid Fuel firing

No. of sources in subcategory

826

826

826

No. of sources with data

91

177

190

No. in MACT floor

11

22

23

Avg of top 12%, lb/MMBtu

1.40E-03

1.91E-06

2.59E-04

99% UPL of top 12% (test runs), lb/MMBtu

0.00323

2.78E-06

3.26E-04

99% UPL with fuel variability of top 12%, lb/MMBtu

3.97E-06

8.04E-04

Units designed for other gas firing

No. of sources in subcategory

199

199

199

No. of sources with data

13

8

8

No. in MACT floor

2

1

1

Avg of top 12%, lb/MMBtu

0.011

8.25E-08

1.70E-06

99% UPL of top 12% (test runs), lb/MMBtu

0.045

1.86E-07

2.50E-06

For three cases, the proposed new and existing source MACT floors are almost identical because the best performing 12 percent of existing units (for which we have emissions information) is only one or two 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 these subcategories consist of 30 or more units. CAA section 112(d)(3)(A) provides that standards for existing sources shall not be less stringent than “the average emission limitation achieved by the best performing 12 percent of the existing sources (for which the Administrator has emissions information), * * * in the category or subcategory for categories and 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 of 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 units setting the existing source floor with the result that the new and existing source MACT floors are almost identical. In contrast, if these subcategories had less than 30 sources, we would be required to use the top five best performing sources, rather than the one or 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 or two. First, it seems evident that Congress was concerned 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 less for subcategories with 30 or more sources. We are specifically requesting comment on this interpretation relating to the proposed MACT floors.

9

9

The impact of using a minimum of five sources in the MACT floor analyses for these subcategories and HAP are presented in the Memorandum “MACT Floor Analysis (2010) for the Industrial, Commercial, and Institutional Boilers and Process Heaters National Emission Standards for Hazardous Air Pollutants—Major Sources” located in the Docket.

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 3 of this preamble presents the number of units in each of the 11 subcategories, along with the number of units from which we have collected emission data. Table 3 also presents for each subcategory (for 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 UPL of top 12 percent) which includes the variability across the best performing units and the long term variability.

We calculated the MACT floors based on the upper 99th 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

Dioxin/Furan (TEQ)

Stoker—Coal

No. of sources in subcategory

361

361.

No. of sources with data

61

14.

No. in MACT floor

8

2.

Avg of top 12%

21.4 ppm @ 3% O

2

0.00182 ng/dscm @ 7% O

2

.

99% UPL of top % (test runs)

48.8 ppm @ 3% O

2

0.00274 ng/dscm @ 7% O

2

.

Fluidized Bed—Coal

No. of sources in subcategory

31

31.

No. of sources with data

17

12.

No. in MACT floor

3

2.

Avg of top 12%

12.5 ppm @ 3% O

2

0.000471 ng/dscm @ 7% O

2

.

99% UPL of top % (test runs)

21.4 ppm @ 3% O

2

0.00168 ng/dscm @ 7% O

2

.

PC—Coal

No. of sources in subcategory

186

186.

No. of sources with data

41

10.

No. in MACT floor

5

2.

Avg of top 12%

19.2 ppm @ 3% O

2

0.00158 ng/dscm @ 7% O

2

.

99% UPL of top % (test runs)

82.8 ppm @ 3% O

2

0.00307 ng/dscm @ 7% O

2

.

Stoker—Biomass

No. of sources in subcategory

320

320.

No. of sources with data

119

16.

No. in MACT floor

15

2.

Avg of top 12%

203 ppm @ 3% O

2

0.000819 ng/dscm @ 7% O

2

.

99% UPL of top % (test runs)

551 ppm @ 3% O

2

0.00339 ng/dscm @ 7% O

2

.

Fluidized Bed—Biomass

No. of sources in subcategory

12

12.

No. of sources with data

7

6.

No. in MACT floor

5

5.

Avg of top 12%

97.1 ppm @ 3% O

2

0.00507 ng/dscm @ 7% O

2

.

99% UPL of top 12% (test runs)

245 ppm @ 3% O

2

0.0127 ng/dscm @ 7% O

2

.

Suspension Burner/Dutch Oven

No. of sources in subcategory

62

62.

No. of sources with data

17

3.

No. in MACT floor

3

1.

Avg of top 12%

362 ppm @ 3% O

2

0.00952 ng/dscm @ 7% O

2

.

99% UPL of top 12% (test runs)

1010 ppm @ 3% O

2

0.0279 ng/dscm @ 7% O

2

.

Fuel Cell—Biomass

No. of sources in subcategory

26

26.

No. of sources with data

16

7.

No. in MACT floor

5

5.

Avg of top 12%

130 ppm @ 3% O

2

0.00552 ng/dscm @ 7% O

2

.

99% UPL of top 12% (test runs)

262 ppm @ 3% O

2

0.0148 ng/dscm @ 7% O

2

.

Units designed for Liquid fuel firing

No. of sources in subcategory

826

826.

No. of sources with data

116

17.

No. in MACT floor

14

3.

Avg of top 12%

0.443 ppm @ 3% O

2

0.000733 ng/dscm @ 7% O

2

.

99% UPL of top 12% (test runs)

0.911 ppm @ 3% O

2

0.00182 ng/dscm @ 7% O

2

.

Units designed for other gases firing

No. of sources in subcategory

199

199.

No. of sources with data

75

5.

No. in MACT floor

9

1.

Avg of top 12%

0.0737 ppm @ 3% O

2

0.00267 ng/dscm @ 7% O

2

.

99% UPL of top 12% (test runs)

0.134 ppm @ 3% O

2

0.00828 ng/dscm @ 7% O

2

.

For organic HAP, as previously discussed above for fuel-related HAP, 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, 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 (steam production) decreases. Most industrial or commercial/institutional units do not continuously operate at or 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 operational 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 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 CEMS data shows that CO (as a surrogate for non-dioxin organic HAP) from best performing units did not vary much when such unit is operated at below design capacity. Therefore, even though ICI units, due to steam demand, may operate at these low load conditions, no additional variability due to operating load needs to be accounted for since the 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, we are proposing to add no additional variability factor to account for load variability to the MACT floor 99 percent UPL values determined from the stack test data for CO emissions.

This approach reasonably ensures that the emission limit selected as the MACT floor adequately represents the average level of control actually achieved by units in the top 12 percent in each subcategory, 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 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.

As was the case for the three fuel-dependent MACT floors, the proposed new and existing source MACT floors for eight combustion-dependent subcategories are almost identical because the best performing 12 percent of units (for which we have emissions information) is only one or two sources. Again, the reason we look to the best performing 12 percent of sources is that these subcategories consist of 30 or more units. In contrast, if these subcategories had less than 30 sources, we would be required to use the top five best performing sources, rather than the one or two that comprise the top 12 percent. As stated previously, 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. We are specifically requesting comment on this interpretation 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 provisions of CAA sections 112(d) or (f), in those cases where, in the judgment of the Administrator, it is not feasible to enforce an emission standard. CAA section 112(h)(2)(B) further defines the term “not feasible” in this context to apply when “the application of measurement technology to a particular class of sources is not practicable due to 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 surrogate 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 sample small diameter (less than 12 inches) stacks. For example, in these 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 existing 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 units 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

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to evaluate 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 compliance costs imposed on each facility would not only include the costs of the stack tests 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 and process heaters to achieve the proposed emission limits would be $6.3 billion. In addition to these costs, additional costs would be incurred because 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 temporary scaffolding. Many establishments in each industry, commercial, or institutional sector are associated with multiple (as many as a 700) small units.

10

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.

The results of the analysis indicate that the annual costs for testing and monitoring costs alone 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 Administrator has determined 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 limitations described above. Thus, a work practice, as discussed below, is being proposed to limit the emission of HAP for existing boilers and process heaters having a heat input capacity of less than 10 million Btu per hour. We are specifically requesting comment on whether a threshold higher than 10 million Btu per hour meets the technical and economic 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. Fuel usage can be reduced by improving the combustion efficiency of the unit, such as, by a tune-up. As combustion efficiency decreases, fuel usage must increase to maintain

constant energy output. This increased fuel use results 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 Ts of combustion. Good combustion practice (GCP), in terms of combustion units, could be defined as the system design and work practices expected to minimize organic HAP emissions.

We have obtained information on units that reported using GCP, as part of the information collection effort for the NESHAP. The data that we have suggests that units typically conduct tune-ups. We also reviewed State regulations and permits. The work practices listed in State regulations includes tune-ups (10 States), operator training (1 State), periodic inspections (2 States), and operation in accordance with manufacturer specifications (1 State). Of the units 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 units in each of the subcategories are subject to a tune-up requirement. Therefore, the proposed work practice of a tune-up

11

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

11

Tune-up procedure is specified in section 63.7540 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.

We are also proposing a work practice standard under section 112(h) that would require an annual tune-up for existing boilers and process heaters combusting natural gas or refinery gas. These boilers and process heaters are units 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 work practice standard is being proposed for several reasons. First, the capital costs estimated for installing controls on these boilers and process heaters to comply with MACT limits for the five HAP groups is over $14 billion. This cost includes installation of a combination system of a fabric filter (for PM, mercury, and D/F control) and a wet scrubber (for HCl control). This capital cost is higher than the estimated combined capital cost for boilers and process heaters in all of the other subcategories. The projected control system needed for boilers and process heaters in the other subcategories is also a combined fabric 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 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 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 Table 4 of this preamble for the Gas 1 and Metal Process Furnace subcategories should be promulgated. Comments should include detailed information regarding why emission limits for these gas-fired boilers and process heaters are appropriate.

Table 4—Summary of MACT Floor Results for the Gas 1 and Metal Process Furnace Subcategories

Subcategory

Parameter

PM

Mercury

HCl

CO

Dioxin/furan

(total TEQ)

Units designed for NG/RG firing

No. of sources in subcategory

10,783

10,783

10,783

10,783

10,783.

No. of sources with data

144

14

11

754

8.

No. in MACT floor

18

2

2

91

1.

Avg of top 12%

0.00388 lb/MMBtu

1.1E-07 lb/MMBtu

1.01E-04 lb/MMBtu

1.45 ppm @ 3% oxygen

0.0026 ng/dscm @ 7% oxygen.

99% UPL of top 12% (test runs)

0.03 lb/MMBtu

2.0E-07 lb/MMBtu

0.0002 lb/MMBtu

20 ppm @ 3% oxygen

0.01 ng/dscm @ 7% oxygen.

Metal Process Furnaces

No. of sources in subcategory

749

749

749

749

749.

No. of sources with data

9

7

9

15

7.

No. in MACT floor

2

1

2

2

1.

Avg of top 12%

0.0047 lb/MMBtu

3.3E-08 lb/MMBtu

1.92E-04 lb/MMBtu

0.38 ppm @ 3% oxygen

0.0026 ng/dscm @ 7% oxygen.

99% UPL of top 12% (test runs)

0.02 lb/MMBtu

2.0E-07 lb/MMBtu

0.0004 lb/MMBtu

2 ppm @ 3% oxygen

0.004 ng/dscm @ 7% oxygen.

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 options more stringent than the MACT floor level of control (

i.e.,

technologies or other work practices that could result in lower emissions) for the different subcategories. 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.

We could not identify better HAP emissions reduction approaches that could achieve greater emissions reductions of HAP than the control technology combination (fabric filter, carbon injection, scrubber, and GCP) that we expect will be used to meet the MACT floor level of control.

For each subcategory, fuel switching to natural gas is an option that would reduce HAP emissions. We determined that fuel switching was not an appropriate beyond-the-floor option. First, natural gas supplies are not available 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 gas 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 $13.5 billion compared with $3.5 billion under the floor approach. The emission reduction associated with fuel switching was estimated to be 4,296 tons per year for metallic HAP, 8 tons per year for mercury, and 50,332 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 Emissions 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 as a beyond-the-floor option for HAP emissions. An energy assessment 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 facility given its operating parameters. An energy assessment refers to a process which involves a thorough examination of potential savings from energy efficiency improvements, pollution prevention, and productivity improvement. It leads to the reduction of emissions of pollutants through process changes and other efficiency modifications. Besides reducing operating and maintenance costs, improving energy efficiency reduces negative impacts on the environment and results in reduced emissions and improved public health. Improvement in energy efficiency results in decreased fuel use which results in a corresponding decrease in emissions (both HAP and non-HAP) from the combustion unit, but not necessarily a decrease in emissions of all HAP emitted. The Department of Energy has conducted energy assessments at selected manufacturing facilities and reports that facilities can reduce fuel/energy use by 10 to 15 percent by using best practices to increase their energy efficiency. Many best practices are considered pollution prevention because they reduce the amount of fuel combusted which results in a corresponding 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 the facility. The total annualized cost if each major source facility conducted an energy assessment is estimated at $26 million. If a facility implemented the cost-effective energy conservation measures identified in the energy assessment, it would potentially result in greater HAP reduction than achieved by a boiler tune-up alone and potentially reducing HAP emissions (HCl, mercury, non-mercury metals, and VOC) by an additional 820 to 1,640 tons per year. In addition, the costs of any energy conservation improvement will be offset by the cost savings in lower fuel costs. Therefore, we decided to go beyond the MACT floor for this proposed rule for the existing units. These proposed standards for existing units include the requirement of a performance of an energy assessment to identify cost-effective energy conservation measures. Since there was insufficient information to determine if requiring implementation of cost-effective measures were economically feasible, we are seeking comment on this point.

In this proposed rule, we are defining a cost-effective energy conservation measure to be any measure that has a payback (return of investment) period of 2 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 section 112(d)(2) states that “Emission standards promulgated * * * and applicable to new or existing sources * * * is achievable * * * through application of measures, processes, methods, systems or techniques including, but not limited to measures which * * * reduce the volume of, or eliminate emissions of, such pollutants through process changes, substitution of materials or other modifications * * *”

The purpose of an energy assessment is to identify energy conservation measures (such as, process changes or other modifications to the facility) that can be implemented to 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.

We are proposing that the energy assessment be conducted by energy professionals and/or engineers that have expertise that cover all energy using systems, processes, and equipment. We are aware of, at least, two organizations that provide certification of specialists in evaluating energy systems. We are proposing that a qualified specialized is someone who has successfully completed the Department of Energy's Qualified Specialist Program for all systems or a professional engineer certified as a Certified Energy Manager by the Association of Energy Engineers.

As part of the energy assessment, we are proposing that the facility assess its energy management program and

practices using EPA's ENERGY STAR Facility Energy Management Assessment Matrix. ENERGY STAR has a simple facility energy management assessment tool that can be used as part of the assessment process. This tool identifies gaps in current practices. Facilities, as part of the requirement, would identify steps to close the management gaps. We are also proposing that the facility develop an energy management program according to the ENERGY STAR Guidelines for Energy Management (

see www.energystar.gov/guidelines

).

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The location of the guidance is:

http://www.energystar.gov/index.cfm?c=guidelines.assess_facility_energy.

We are specifically requesting comment on: (1) Whether our estimates of the assessment costs are correct; (2) is there adequate access to certified assessors; (3) are there other organizations for certifying energy engineers; (4) are online tools adequate to inform the facility's decision to make efficiency upgrades; (5) 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; (6) what rate of return should be used; and (7) are there other guidelines for energy management beside ENERGY STAR's that would be appropriate.

We 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 considered proposing that facilities with boilers or process heaters combusting refinery gas install and maintain a carbon adsorber bed system

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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 mercury and additional mercury reductions can be achieved from units combusting refinery gas. Consequently, we analyzed the mercury emissions reductions and additional cost of adopting this work practice. The annualized cost of the carbon adsorber bed system to treat the refinery gas prior to combustion is estimated to be about 1.6 billion dollars with a mercury emission reduction of 0.8 tons. The results indicated that while additional mercury emissions reductions would be realized, the costs would be too high to 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 in 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.

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Carbon adsorption of mercury can be accomplished by (a) injecting dry carbon with 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 flows 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 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.)

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 using the available data. We believe that the subcategories we selected are appropriate.

EPA requests comments on whether additional or different subcategories should be considered. Comments should include detailed information regarding why a new or different subcategory is appropriate (based on the available data or adequate data submitted with the comment), how EPA should define any additional/different subcategories, how EPA should account for varied or changing fuel mixtures, and how EPA should use the available data to determine the MACT floor for any new or different 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. This 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?

Similar to the MACT floor process 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 subcategory of sources by ranking the emission test results from units within the subcategory from lowest to highest to identify the best controlled similar source. The MACT floor limits for each of the 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 limits for new sources were 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 emission 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 current information, fuel-related HAP levels in the various fuels can vary significantly over time. The variations in fuel-related HAP inputs directly translate to a variability of fuel-related HAP stack emissions.

As previously discussed above, we account for variability of the best-controlled source in setting floors, not only because variability is an element of performance, but because it is reasonable to assess best performance over time. If we do not account for this variability, we would expect that 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 calculated the MACT floor based on 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 operational variability.

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.

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 performance achieved by the average of the best performing 12 percent of sources, the MACT floors for new units are meant to reflect the emission control that is achieved in practice by the best controlled source. Thus, for existing units, we are concerned about estimating the central tendency of a set of multiple units, while for new units, we are concerned about estimating the level of control that is representative of that achieved by a single best controlled source. As with the analysis for existing sources, the new unit analysis must account for variability. To accomplish this for new sources, for the fuel dependent HAP emissions, we determined what the best controlled source has achieved 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 subcategory. These approaches, respectively, represent the most reasonable way to estimate performance 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 information 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 analyses from the best-controlled source. Once we calculated the fuel dependent variability factors, we applied these factors to the average measured emissions performance of the best controlled similar source to derive the MACT floor level of control. This approach reasonably estimates the best source's level of 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 described earlier, we are using PM as a surrogate for non-mercury metallic HAP and HCl as a surrogate for the acid gases. Table 5 presents for each subcategory and fuel-related HAP the average emission level of the best controlled similar source and the MACT floor (99 percent UPL) which includes the variability across the best controlled similar source and the long term variability of that source.

Table 5—Summary of MACT Floor Results for the Fuel-Related HAP for New Sources

Subcategory

Parameter

PM

Lb/MMBtu

Mercury

Lb/MMBtu

HCl

Lb/MMBtu

Units designed for Coal firing

Avg of top performer

0.000396

1.18E-07

3.85E-05

99% UPL of top performer (test runs)

0.000928

3.89E-07

5.21E-05

Units designed for Biomass firing

Avg of top performer

0.00216

9.73E-08

7.85E-04

99% UPL of top performer (test runs)

0.00711

1.86E-07

3.07E-03

Units designed for Liquid Fuel firing

Avg of top performer

0.000511

5.87E-08

3.99E-04

99% UPL of top performer (test runs)

0.00154

2.47E-07

9.80E-04

Units designed for other gas firing

Avg of top performer

0.00042

8.25E-08

1.70E-06

99% UPL of top performer (test runs)

0.0024

1.86E-07

2.50E-06

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 6 presents for each subcategory and CO and D/F the average emission level of the best controlled similar source and the MACT floor (99 percent UPL) which includes the variability across the best controlled similar source and the long term variability of that source.

Table 6—Summary of MACT Floor Results 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

4.29

1.52E-03

99% UPL of top performer (test runs)

6.53

2.82E-03

Fluidized Bed—Coal

Avg of top performer

8.26

9.05E-06

99% UPL of top performer (test runs)

*39.9

2.54E-05

PC—Coal

Avg of top performer

25.0

1.04E-03

99% UPL of top performer (test runs)

*97.5

1.47E-03

Stoker—Biomass

Avg of top performer

920

1.52E-05

99% UPL of top performer (test runs)

*3730

4.86E-05

Fluidized Bed—Biomass

Avg of top performer

25.8

2.27E-03

99% UPL of top performer (test runs)

34.2

6.48E-03

Suspension Burner/Dutch Oven.

Avg of top performer

352

9.52E-03

99% UPL of top performer (test runs)

*1050

2.79E-02

Fuel Cell—Biomass

Avg of top performer

110

2.42E-04

99% UPL of top performer (test runs)

*264

4.17E-04

Units designed for Liquid fuel firing

Avg of top performer

0.125

1.09E-03

99% UPL of top performer (test runs)

0.125

1.52E-03

Units designed for other gases firing

Avg of top performer

0.0129

2.67E-03

99% UPL of top performer (test runs)

0.0129

8.28E-03

* Value is higher than existing floor limit in the same subcategory. Therefore defaulted to existing floor limit for the same subcategory.

For organic HAP, as 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 assess best performance over time. Here, we know that CO (as a surrogate for non-dioxin organic HAP)

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