Vol. 78 Thursday, 

No. 21 January 31, 2013 

Part V 

Environmental Protection Agency 

40 CFR Part 63 

National Emission Standards for Hazardous Air Pollutants for Major 

Sources: Industrial, Commercial, and Institutional Boilers and Process 

Heaters; Final Rule 


tkelley on DSK3SPTVN1PROD with 
7138 Federal Register / Vol. 78, No. 21 / Thursday, January 31, 2013 / Rules and Regulations 

ENVIRONMENTAL PROTECTION 

AGENCY 

40 CFR Part 63 

[EPA–HQ–OAR–2002–0058; FRL–9676–8] 

RIN 2060–AR13 

National Emission Standards for 

Hazardous Air Pollutants for Major 

Sources: Industrial, Commercial, and 

Institutional Boilers and Process 

Heaters 

AGENCY: Environmental Protection 

Agency (EPA). 

ACTION: Final rule; notice of final action 

on reconsideration. 

SUMMARY: In this action the EPA is 

taking final action on its reconsideration 

of certain issues in the emission 

standards for the control of hazardous 

air pollutants from new and existing 

industrial, commercial, and institutional 

boilers and process heaters at major 

sources of hazardous air pollutants, 

which were issued under section 112 of 

the Clean Air Act. As part of this action, 

the EPA is making technical corrections 

to the final rule to clarify definitions, 

references, applicability and compliance 

issues raised by petitioners and other 

stakeholders affected by this rule. On 

March 21, 2011, the EPA promulgated 

national emission standards for this 

source category. On that same day, the 

EPA also published a notice announcing 

its intent to reconsider certain 

provisions of the final rule. Following 

these actions, the Administrator 

received several petitions for 

reconsideration. After consideration of 

the petitions received, on December 23, 

2011, the EPA proposed revisions to 

certain provisions of the March 21, 

2011, final rule, and requested public 

comment on several provisions of the 

final rule. The EPA is now taking final 

action on the proposed reconsideration. 

DATES: The May 18, 2011 (76 FR28661), 

delay of the effective date revising 

subpart DDDDD at 76 FR 15451 (March 

21, 2011) is lifted January 31, 2013. The 

amendments in this rule to 40 CFR part 

63, subpart DDDDD are effective as of 

April 1, 2013. 

ADDRESSES: The EPA established a 

single docket under Docket ID No. EPA– 

HQ–OAR–2002–0058 for this action. All 

documents in the docket are listed on 

the http://www.regulations.gov Web 

site. Although listed in the index, some 

information is not publicly available, 

e.g., confidential business information 

or other information whose disclosure is 

restricted by statute. Certain other 

material, such as copyrighted material, 

is not placed on the Internet and will be 

publicly available only in hard copy 

form. Publicly available docket 

materials are available either 

electronically through http:// 

www.regulations.gov or in hard copy at 

the EPA’s Docket Center, Public Reading 

Room, EPA West Building, Room 3334, 

1301 Constitution Avenue NW., 

Washington, DC 20004. This Docket 

Facility is open from 8:30 a.m. to 4:30 

p.m., Monday through Friday, excluding 

legal holidays. The telephone number 

for the Public Reading Room is (202) 

566–1744, and the telephone number for 

the Air Docket is (202) 566–1742. 

FOR FURTHER INFORMATION CONTACT: Mr. 

Jim Eddinger, Energy Strategies Group, 

Sector Policies and Programs Division, 

(D243–01), Office of Air Quality 

Planning and Standards, U.S. 

Environmental Protection Agency, 

Research Triangle Park, North Carolina 

27711; Telephone number: (919) 541– 

5426; Fax number (919) 541–5450; 

Email address: eddinger.jim@epa.gov. 

SUPPLEMENTARY INFORMATION: 

Executive Summary 

Purpose of This Regulatory Action 

The EPA is taking final action on its 

proposed reconsideration of certain 

provisions of its March 21, 2011, final 

rule that established standards for new 

and existing industrial, commercial, and 

institutional boilers and process heaters 

at major sources of hazardous air 

pollutants. Section 112(d) of the CAA 

requires the EPA to regulate HAP from 

major stationary sources based on the 

performance of MACT. Section 112(h) of 

the CAA allows the EPA to establish 

work practice standards in lieu of 

numerical emission limits only in cases 

where the agency determines that it is 

not feasible to prescribe or enforce an 

emission standard, including 

circumstances in which the agency 

determines that the application of 

measurement methodology is not 

practicable due to technological and 

economic limitations. The EPA is 

revising certain MACT standards 

established in March 2011 for boilers 

and process heaters, including 

standards for CO—as a surrogate for 

organic HAP; HCl—as a surrogate for 

acid gas HAP; Hg; TSM or filterable 

PM—as a surrogate for non-Hg metallic 

HAP; and dioxin/furan. 

This final rule amends certain 

provisions of the final rule issued by the 

EPA on March 21, 2011. The EPA 

delayed the effective date of the 2011 

rule in a May 18, 2011, notice, but that 

delay notice was vacated by the U.S. 

District Court for the District of 

Columbia on January 9, 2012, and the 

March 2011 final rule was, therefore, in 

effect until publication of this action. 

Summary of Major Reconsideration 

Provisions 

In general, this final rule requires 

facilities classified as major sources of 

HAP with affected boilers or process 

heaters to reduce emissions of harmful 

toxic air emissions from these 

combustion sources. This will improve 

air quality and protect public health in 

communities where these facilities are 

located. 

Recognizing the diversity of this 

source category and the multiple sectors 

of the economy this final rule effects, 

the EPA is revising certain subcategories 

for boilers and process heaters in this 

action that were established in the 

March 2011 final rule, based on the 

design of the combustion equipment. 

These revisions result in 19 

subcategories for the boilers and process 

heaters source category. Numerical 

emission limits are established for most 

of the subcategories for five pollutants, 

CO, HCl, Hg, and PM or TSM. The 

review of existing data and 

consideration of new data have resulted 

in changes to some of the emission 

limits contained in the March 2011 final 

rule. Overall, for both new and existing 

affected units, about 30 percent of the 

emission limits are more stringent, half 

are less stringent, and 20 percent 

unchanged as compared to the March 

2011 final rule. Also, based on its 

review and analysis of new data 

submissions, the EPA is establishing an 

alternative emission standard for CO, 

based on CEMS data for several 

subcategories with CO CEMS data 

available. This alternative standard is 

based on a 30-day rolling average for 

subcategories for which sufficient CEMS 

data were available for more than a 30- 

day period, or a 10-day rolling average 

for subcategories for which CEMS data 

were available for less than a 30-day 

period, and provides additional 

compliance flexibility to sources. All of 

the subcategories are subject to periodic 

tune-up work practices for dioxin/furan 

emissions. 

The compliance dates for the rule are 

January 31, 2016, for existing sources 

and, January 31, 2013, or upon startup, 

whichever is later, for new sources. New 

sources are defined as sources that 

began operation on or after June 4, 2010. 

Costs and Benefits 

The final rule affects 1,700 existing 

major source facilities with an estimated 

14,136 boilers and process heaters and 

the EPA projects an additional 1,844 

new boilers and process heaters to be 

subject to this final rule over the next 3 


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Federal Register / Vol. 78, No. 21 / Thursday, January 31, 2013 / Rules and Regulations 7139 

years. This final rule affects multiple 

sectors of the economy including small 

entities. Table 1 summarizes the costs 

and benefits associated with this final 

rule. A more detailed discussion of the 

costs and benefits of this final rule is 

provided in section VI of this preamble. 

TABLE 1—SUMMARY OF THE MONETIZED BENEFITS, SOCIAL COSTS AND NET BENEFITS FOR THE FINAL BOILER MACT 

RECONSIDERATION IN 2015 

[Millions of 2008$] 1

3 percent discount 

rate 

7 percent discount 

rate 

Total Monetized Benefits 2 ............................................................................................................... $27,000 to $67,000 ... $25,000 to $61,000. 

Total Social Costs 3 ......................................................................................................................... $1,400 to $1,600 ....... $1,400 to $1,600. 

Net Benefits ..................................................................................................................................... $26,000 to $65,000 ... $23,000 to $59,000. 

Non-monetized Benefits .................................................................................................................. Health effects from exposure to HAP (39,000 

tons of HCl, 500 tons of HF, 3,100 to 5,300 

pounds of Hg and 2,500 tons of other metals). 

Health effects from exposure to other criteria 

pollutants (180,000 tons of CO and 572,000 

tons of SO2). 

Ecosystem effects. 

Visibility impairment. 

1All estimates are for the implementation year (2015), and are rounded to two significant figures. 

2The total monetized co-benefits reflect the human health benefits associated with reducing exposure to PM2.5 through reductions of PM2.5

precursors such as directly emitted particles, SO2, and NOX and reducing exposure to ozone through reductions of VOC. It is important to note 

that the monetized benefits include many but not all health effects associated with PM2.5 exposure. Monetized benefits are shown as a range 

from Pope et al. (2002) to Laden et al. (2006). These models assume that all fine particles, regardless of their chemical composition, are equally 

potent in causing premature mortality because the scientific evidence is not yet sufficient to support the development of differential effects estimates by particle type. These estimates include the energy disbenefits valued at $24 million (using the 3 percent discount rate), which do not 

change the rounded totals. CO2-related disbenefits were calculated using the ‘‘social cost of carbon,’’ which is discussed further in the RIA. 3The methodology used to estimate social costs for one year in the multimarket model using surplus changes results in the same social costs 

for both discount rates. 

Acronyms and Abbreviations. The 

following acronyms and abbreviations 

are used in this document. 

ACC American Chemistry Council 

ACCCI American Coke and Coal Chemicals 

Institute 

AF&PA American Forest and Paper 

Association 

AHFA American Home Furnishings 

Alliance 

AISI American Iron and Steel Institute 

AMP American Municipal Power Inc. 

AIE Alliance for Industrial Efficiency 

APCD air pollution control devices 

API American Petroleum Institute 

AIF Auto Industry Forum 

BFG Blast furnace gas 

BLDS Bag leak detection system 

BCSE The Business Council for Sustainable 

Energy 

CIBO Council of Industrial Boiler Owners 

CO Carbon monoxide 

CO2 Carbon dioxide 

CEMS Continuous emissions monitoring 

system 

CEG Citizens Energy Group 

CAA Clean Air Act 

CFR Code of Federal Regulations 

CPMS Continuous parameter monitoring 

system 

CMI CraftMaster Manufacturing Inc. 

ERT Electronic Reporting Tool 

ESP Electrostatic precipitator 

EPA Environmental Protection Agency 

FBC Fluidized bed combustion 

FR Federal Register 

FSI Florida Sugar Industry 

GPSP Great Plains Synfuels Plant 

HAP Hazardous air pollutants 

HBES Health-based emissions standard 

HF Hydrogen fluoride 

Hg Mercury 

HCl Hydrogen chloride 

kWh Kilowatt hours 

ISO International Standards Organization 

lb Pounds 

LFG Landfill gas 

MACT Maximum achievable control 

technology 

MATS Mercury Air Toxics Standards 

MSU Michigan State University 

MMBtu Million British thermal units 

NESHAP National Emission Standards for 

Hazardous Air Pollutants 

NPRA National Petrochemical and Refiners 

Association 

NTTAA National Technology Transfer and 

Advancement Act 

NAICS North American Industry 

Classification System 

NOX Nitrogen oxide 

NSR New Source Review 

OMB Office of Management and Budget 

PM Particulate matter 

PSU Penn State University 

PS Performance Specification 

ppm Parts per million 

QA Quality assurance 

QC Quality control 

RFA Regulatory Flexibility Act 

RIA Regulatory Impact Analysis 

RPU Rochester Public Utilities 

RTC Response to comment 

SCR Selective catalytic reduction 

SNCR Selective non-catalytic reduction 

SO2 Sulfur dioxide 

TBtu/yr Trillion British thermal units per 

year 

THC Total hydrocarbon 

TSM Total selected metals 

TTN Technology Transfer Network 

tpy Tons per year 

UMRA Unfunded Mandates Reform Act of 

1995 

U.S. United States 

USCHPA US Clean Heat Power Association 

US Sugar United States Sugar Corporation 

UPL Upper prediction limit 

UARG Utility Air Regulatory Group 

VCS Voluntary Consensus Standards 

VOC Volatile organic compounds 

WM Waste Management Inc. 

WEPCO Wisconsin Electric Power 

Company 

WWW Worldwide Web 

Organization of this Document. The 

information presented in this preamble 

is organized as follows: 

I. General Information 

A. Does this action apply to me? 

B. Where can I get a copy of this 

document? 

C. Judicial Review 

II. Background Information 

A. Chronological History of Related 

Actions 

III. Summary of This Final Rule 

A. What is an affected source? 

B. What are the subcategories of boilers 

and process heaters? 

C. What emission limits and work practice 

standards are being finalized? 

D. What are the requirements during 

periods of startup and shutdown? 

E. What are the testing and initial 

compliance requirements? 

F. What are the continuous compliance 

requirements? 


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G. What are the compliance dates? 

IV. Summary of Significant Changes Since 

Proposal 

A. Applicability 

B. Subcategories 

C. Performance Test Requirements 

D. Emission Limits 

E. Work Practice Requirement 

F. Averaging Times Definitions 

G. Energy Assessment 

H. Startup and Shutdown Definitions 

I. Fuel Sampling Frequency 

J. Affirmative Defense 

V. Other Actions We Are Taking 

VI. Impacts of This Final Rule 

A. What are the incremental air impacts? 

B. What are the incremental water and 

solid waste impacts? 

C. What are the incremental energy 

impacts? 

D. What are the incremental cost impacts? 

E. What are the economic impacts? 

F. What are the benefits of this final rule? 

G. What are the incremental secondary air 

impacts? 

VII. Statutory and Executive Order Reviews 

A. Executive Order 12866: Regulatory 

Planning and Review and Executive 

Order 13563: Improving Regulation and 

Regulatory Review 

B. Paperwork Reduction Act 

C. Regulatory Flexibility Act 

D. Unfunded Mandates Reform Act 

E. Executive Order 13132: Federalism 

F. Executive Order 13175: Consultation 

and Coordination with Indian Tribal 

Governments 

G. Executive Order 13045: Protection of 

Children from Environmental Health 

Risks and Safety Risks 

H. Executive Order 13211: Actions 

Concerning Regulations That 

Significantly Affect Energy Supply, 

Distribution, or Use 

I. National Technology Transfer and 

Advancement Act 

J. Executive Order 12898: Federal Actions 

to Address Environmental Justice in 

Minority Populations and Low-Income 

Populations 

K. Congressional Review Act 

I. General Information 

A. Does this action apply to me? 

The regulated categories and entities 

potentially affected by this action 

include: 

TABLE 2—POTENTIAL REGULATED CATEGORIES AND ENTITIES AFFECTED

Category NAICS code1 Examples of potentially regulated entities 

Any industry using a boiler or process heater as defined in the final 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 

regulated by this reconsideration action. 

To determine whether your facility may 

be affected by this reconsideration 

action, you should examine the 

applicability criteria in 40 CFR 63.7485 

of subpart DDDDD (National Emission 

Standards for Hazardous Air Pollutants 

(NESHAP) for Industrial, Commercial, 

and Institutional Boilers and Process 

Heaters). If you have any questions 

regarding the applicability of this final 

rule 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. Where can I get a copy of this 

document? 

In addition to being available in the 

docket, an electronic copy of this action 

will also be available on the WWW 

through the TTN. Following signature, a 

copy of the action will be posted on the 

TTN’s policy and guidance page for 

newly proposed or promulgated rules at 

the following address: http:// 

www.epa.gov/ttn/oarpg/. The TTN 

provides information and technology 

exchange in various areas of air 

pollution control. 

C. Judicial Review 

Under the CAA section 307(b)(1), 

judicial review of this final rule is 

available only by filing a petition for 

review in the U.S. Court of Appeals for 

the District of Columbia Circuit by April 

1, 2013. Under CAA section 

307(d)(7)(B), only an objection to this 

final rule that was raised with 

reasonable specificity during the period 

for public comment can be raised during 

judicial review. Note, under CAA 

section 307(b)(2), the requirements 

established by this final rule may not be 

challenged separately in any civil or 

criminal proceedings brought by the 

EPA to enforce these requirements. 

II. Background Information 

A. Chronological History of Related 

Actions 

On March 21, 2011, the EPA issued 

final standards for new and existing 

industrial, commercial, and institutional 

boilers and process heaters, pursuant to 

its authority under section 112 of the 

CAA. On the same day as the final rule 

was issued, the EPA stated in a separate 

notice that it planned to initiate a 

reconsideration of several provisions of 

the final rule. This reconsideration 

notice identified several provisions of 

the March 2011 final rule where 

additional public comment was 

appropriate. This notice also identified 

several issues of central relevance to the 

rulemaking where reconsideration was 

appropriate under CAA section 307(d). 

On May 18, 2011, the EPA issued a 

notice to postpone the effective date of 

the March 21, 2011 final rule. Following 

promulgation of the final rule, the EPA 

received petitions for reconsideration 

from the following organizations 


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(‘‘Petitioners’’): AIE, USCHPA, Alyeska 

Pipeline, ACC, AHFA, AISI, ACCCI, 

AMP, API, NPRA, AIF, Citizens Energy 

Group (CEG), CIBO, CMI, District 

Energy St. Paul, FSI, GPSP, Hovensa 

L.L.C., Tesoro Hawaii Corp., Industry 

Coalition (AF&PA et al.), JELD–WEN 

Inc., MSU, PSU, Purdue University, 

Renovar Energy Corp., RPU, Sierra Club, 

Southeastern Lumber Manufacturers 

Association, State of Washington 

Department of Ecology, BCSE, UARG, 

US Sugar, WM and WEPCO. Copies of 

these petitions are provided in the 

docket (see Docket ID No. EPA–HQ– 

OAR–2002–0058). Petitioners, pursuant 

to CAA section 307(d)(7)(B), requested 

that the EPA reconsider numerous 

provisions in the rule. On December 23, 

2011, the EPA granted the petitions for 

reconsideration on certain issues, and 

proposed certain revisions to the final 

rule in response to the reconsideration 

petitions and to address the issues that 

the EPA previously identified as 

warranting reconsideration. That 

proposal solicited comment on several 

specific aspects of the rule, including: 

• Revising the proposed 

subcategories. 

• Solicitation of new data or 

corrections to existing data to revise 

emission standards calculations. 

• Establishing an alternative TSM 

limit. 

• Appropriateness of an alternative 

TSM limit for the liquid subcategories. 

• Establishing work practice 

standards for dioxin/furan emissions. 

• Revising the efficiency assumptions 

for the alternative output-based 

emission standards. 

• Accommodating emissions 

averaging provisions in the alternative 

output-based emission standards. 

• Establishing a mercury fuel 

specification through which gas-fired 

boilers that use a fuel other than natural 

gas or refinery gas may be considered 

Gas 1 units. 

• Establishing a work practice 

standard for limited use units. 

• Providing an affirmative defense for 

malfunction events. 

• Revisions to the monitoring 

requirements for oxygen in the March 

2011 final rule. 

• Establishing a full-load stack test 

requirement for carbon monoxide 

coupled with continuous oxygen 

(oxygen trim) monitoring. 

• Revising PM monitoring 

requirements from CEMS to CPMS and 

exempting biomass units from PM 

CPMS requirements. 

• Revising mercury monitoring 

requirements to allow for an alternative 

mercury CEMS. 

• Considering use of SO2 CEMS to 

demonstrate compliance with HCl 

limits. 

• Minimum data availability 

provisions. 

• Averaging times for monitored 

parameters and pollutants. 

• Revised methods for computing 

minimum detection levels. 

• Providing an alternative CO 

emission limit based on CO CEMS data. 

• Soliciting additional data to set 

MACT floor emission limits for noncontinental liquid units. 

• Selecting a 99 percent confidence 

interval for setting the CO emission 

limit. 

• Tune-up frequencies, timing of 

initial tune-ups and adjusted tune-up 

requirements for shutdown units. 

• Scope and duration of the energy 

assessment and deadline for completing 

the assessment. 

• Revising work practices during 

startup and shutdown. 

• Revisions to certain exemptions, 

including units serving as control 

devices, waste heat process heaters, 

units firing comparable fuels and 

residential units. 

• Revisions to reduced testing 

frequency for emission limits that are 

established at minimum detection 

levels. 

• Removing fuel analysis 

requirements for gas 1 fuels at co-fired 

units. 

• Revisions to automating techniques 

for coal sampling. 

• Revisions to emissions averaging 

across subcategories when units opt to 

switch to natural gas. 

• Consideration of a new subcategory 

for units installed and used in place of 

flares. 

In this action, the EPA is finalizing 

multiple changes to the March 2011 

final rule after considering public 

comments on the items under 

reconsideration. 

III. Summary of This Final Rule 

As stated above, the December 23, 

2011 proposed rule addressed specific 

issues and provisions the EPA identified 

for reconsideration. This summary of 

the final rule reflects the changes to 40 

CFR part 63, subpart DDDDD (March 21, 

2011 final rule) in regards to those 

provisions identified for reconsideration 

and on other discrete matters identified 

in response to comments or data 

received during the comment period. 

Information on other provisions and 

issues not proposed for reconsideration 

is contained in the notice and record for 

the 2011 final rule. [See 76 FR 15608] 

This section summarizes the 

requirements of this action. Section IV 

below provides a summary of the 

significant changes to the March 21, 

2011 final rule. 

A. What is an affected source? 

This final rule revises the list of 

exemptions in § 63.7491 to include 

residential boilers that may be located at 

an industrial, commercial or 

institutional major source. The 

exemption for boilers or process heaters 

used specifically for research and 

development has been revised to 

include boilers used for certain testing 

purposes. 

B. What are the subcategories of boilers 

and process heaters? 

In this final rule, we are finalizing 

separate subcategories for heavy liquidfired, light liquid-fired and liquid-fired 

units in non-continental locations for 

PM and CO, pollutants that are 

dependent on combustor design. In 

addition, a new subcategory for coalfired fluidized bed boilers with 

integrated fluidized bed heat exchangers 

has been included in the final rule for 

CO which is dependent on boiler 

design. Finally, we are finalizing the 

subcategory for PM at coal/fossil solid 

units across all coal combustor designs. 

C. What emission limits and work 

practice standards are being finalized? 

You must meet the emission limits 

presented in Table 3 of this preamble for 

each subcategory of units listed in the 

table. This final rule includes 19 

subcategories, which are based on unit 

design. New and existing units in three 

of the subcategories are subject to work 

practices standards in lieu of emission 

limits for all pollutants. Numeric 

emission limits are finalized for new 

and existing sources in each of the other 

16 subcategories. 

The changes associated with the 

emission limits are due to new data, 

corrections to old data, and inventory 

changes. In summary, for existing 

subcategories, for the HCl emission 

limits, 10 are more stringent, 3 are less 

stringent and 1 remained the same from 

the March 21, 2011 final rule; for the 

mercury emission limits, 3 are more 

stringent and 11 are less stringent from 

the March 21, 2011 final rule; for the 

PM emission limits, 2 are more 

stringent, 7 are less stringent and 5 are 

unchanged from the March 21, 2011 

final rule; and for the CO emission 

limits, 4 are more stringent and 10 are 

less stringent from the March 21, 2011 

final rule. For new subcategories, for the 

HCl emission limits, 13 are less 

stringent and 1 is unchanged from the 

March 21, 2011 final rule; for the 

mercury emission limits, 11 are more 


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stringent, 2 are less stringent and 1 is 

unchanged from the March 21, 2011 

final rule; for the PM emission limits, 9 

are less stringent and 5 are unchanged 

from the March 21, 2011 final rule; and 

for the CO emission limits, 3 are more 

stringent and 11 are less stringent from 

the March 21, 2011 final rule. 

TABLE 3—EMISSION LIMITS FOR BOILERS AND PROCESS HEATERS

[lb/MMBtu heat input basis unless noted; alternative output based limits are not shown in the summary table below] 

Subcategory 

Filterable PM 

(or total selected 

metals) 

(lb per MMBtu of 

heat input) a

HCl 

(lb per 

MMBtu of 

heat 

input) a

Mercury 

(lb per 

MMBtu of 

heat 

input) a

CO 

(ppm @3% 

oxygen) a

Alternate CO 

CEMS limit, 

(ppm @3% 

oxygen) b

Existing—Coal Stoker ............................................................... 0.040 (5.3E–05) ... 0.022 5.7E–06 160 340 

Existing—Coal Fluidized Bed .................................................... 0.040 (5.3E–05) ... 0.022 5.7E–06 130 230 

Existing—Coal Fluidized Bed with FB heat exchanger ............ 0.040 (5.3E–05) ... 0.022 5.7E–06 140 150 

Existing—Coal-Burning Pulverized Coal ................................... 0.040 (5.3E–05) ... 0.022 5.7E–06 130 320 

Existing—Biomass Wet Stoker/Sloped Grate/Other ................. 0.037 (2.4E–04) ... 0.022 5.7E–06 1,500 720 

Existing—Biomass Kiln-Dried Stoker/Sloped Grate/Other ........ 0.32 (4.0E–03) ..... 0.022 5.7E–06 460 ND 

Existing—Biomass Fluidized Bed ............................................. 0.11 (1.2E–03) ..... 0.022 5.7E–06 470 310 

Existing—Biomass Suspension Burner ..................................... 0.051 (6.5E–03) ... 0.022 5.7E–06 2,400 c 2,000 

Existing—Biomass Dutch Ovens/Pile Burners .......................... 0.28 (2.0E–03) ..... 0.022 5.7E–06 770 c 520 

Existing—Biomass Fuel Cells ................................................... 0.020 (5.8E–03) ... 0.022 5.7E–06 1,100 ND 

Existing—Biomass Hybrid Suspension Grate ........................... 0.44(4.5E–04) ...... 0.022 5.7E–06 2,800 900 

Existing—Heavy Liquid ............................................................. 0.062 (2.0E–04) ... 0.0011 2.0E–06 130 ND 

Existing—Light Liquid ................................................................ 0.0079 (6.2E–05) 0.0011 2.0E–06 130 ND 

Existing—non-Continental Liquid .............................................. 0.27 (8.6E–04) ..... 0.0011 2.0E–06 130 ND 

Existing—Gas 2 (Other Process Gases) .................................. 0.0067 (2.1E–04) 0.0017 7.9E–06 130 ND 

New—Coal Stoker ..................................................................... 0.0011 (2.3E–05) 0.022 8.0E–07 130 340 

New—Coal Fluidized Bed ......................................................... 0.0011 (2.3E–05) 0.022 8.0E–07 130 230 

New—Coal Fluidized Bed with FB Heat Exchanger ................. 0.0011 (2.3E–05) 0.022 8.0E–07 140 150 

New—Coal-Burning Pulverized Coal ........................................ 0.0011 (2.3E–05) 0.022 8.0E–07 130 320 

New—Biomass Wet Stoker/Sloped Grate/Other ...................... 0.030 (2.6E–05) ... 0.022 8.0E–07 620 390 

New—Biomass Kiln-Dried Stoker/Sloped Grate/Other ............. 0.030 (4.0E–03) ... 0.022 8.0E–07 460 ND 

New—Biomass Fluidized Bed ................................................... 0.0098 (8.3E–05) 0.022 8.0E–07 230 310 

New—Biomass Suspension Burner .......................................... 0.030 (6.5E–03) ... 0.022 8.0E–07 2,400 c 2,000 

New—Biomass Dutch Ovens/Pile Burners ............................... 0.0032 (3.9E–05) 0.022 8.0E–07 330 c 520 

New—Biomass Fuel Cells ......................................................... 0.020 (2.9E–05) ... 0.022 8.0E–07 910 ND 

New—Biomass Hybrid Suspension Grate ................................ 0.026 (4.4E–04) ... 0.022 8.0E–07 1,100 900 

New—Heavy Liquid ................................................................... 0.013 (7.5E–05) ... 4.4E–04 4.8E–07 130 ND 

New—Light Liquid ..................................................................... 0.0011 (2.9E–05) 4.4E–04 4.8E–07 130 ND 

New—Non-Continental Liquid ................................................... 0.023 (8.6E–04) ... 4.4E–04 4.8E–07 130 ND 

New—Gas 2 (Other Process Gases) ........................................ 0.0067 (2.1E–04) 0.0017 7.9E–06 130 ND 

NA-Not applicable; ND-No data available 

a 3-run average, unless otherwise noted. 

b 30-day rolling average, unless otherwise noted. 

c 10-day rolling average. 

We also are finalizing a work practice 

standard for dioxin/furan emissions 

from all subcategories. 

D. What are the requirements during 

periods of startup and shutdown? 

We are finalizing revised work 

practice standards for periods of startup 

and shutdown to better reflect the 

maximum achievable control 

technology during those periods. In 

addition, we are finalizing definitions of 

startup and shutdown. We are defining 

startup as the period between the state 

of first-firing of fuel in the unit after a 

shutdown to the period where the unit 

first supplies steam. We are defining 

shutdown as the period that begins 

when no more steam is supplied or at 

the point of no fuel being fired in the 

unit. For periods of startup and 

shutdown, we are finalizing the 

following work practice standard: You 

must operate all continuous monitoring 

systems during startup and shutdown. 

For startup, you must use one or a 

combination of the listed clean fuels. 

Once you start firing coal/solid fossil 

fuel, biomass/bio-based solids, heavy 

liquid fuel, or gas 2 (other) gases, you 

must engage all of the applicable control 

devices except limestone injection in 

FBC boilers, dry scrubber, fabric filter, 

SNCR and SCR. You must start your 

limestone injection in FBC boilers, dry 

scrubber, fabric filter, SNCR and SCR 

systems as expeditiously as possible. 

During shutdown while firing coal/solid 

fossil fuel, biomass/bio-based solids, 

heavy liquid fuel, or gas 2 (other) gases 

during shutdown, you must operate all 

applicable control devices, except 

limestone injection in FBC boilers, dry 

scrubber, fabric filter, SNCR and SCR. 

You must comply with all applicable 

emissions and operating limits at all 

times the unit is in operation except for 

periods that meet the definitions of 

startup and shutdown in this subpart, 

during which times you must comply 

with these work practices. You must 

keep records during periods of startup 

or shutdown. You must keep records 

concerning the date, duration, and fuel 

usage during startup and shutdown. 

E. What are the testing and initial 

compliance requirements? 

We are requiring that the owner or 

operator of a new or existing boiler or 

process heater conduct performance 

tests to demonstrate compliance with all 

applicable emission limits. This final 

rule adds the requirement to conduct 

initial and annual stack tests to 

determine compliance with the TSM 

emission limits using EPA Method 29 

for those subcategories with alternate 

TSM limits. 


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Federal Register / Vol. 78, No. 21 / Thursday, January 31, 2013 / Rules and Regulations 7143 

F. What are the continuous compliance 

requirements? 

This final rule removes the 

requirement for units combusting 

biomass with heat input capacities of 

250 MMBtu/hr or greater to install, 

certify, maintain and operate a CEMS 

measuring PM emissions. This final rule 

requires units combusting solid fossil 

fuel or heavy liquid with heat input 

capacities of 250 MMBtu/hr or greater to 

install, certify, maintain, and operate 

PM CPMS. Moreover, owners or 

operators of units combusting solid 

fossil fuel or heavy liquid with heat 

input capacities of 250 MMBtu/hr or 

greater are allowed to install, certify, 

maintain and operate PM CEMS as an 

alternative to the use of PM CPMS, 

consistent with regulations for 

similarly-sized commercial and 

industrial solid waste incinerators units 

and EGUs subject to the MATS. Just as 

units using PM CPMS will not be 

required to conduct parameter 

monitoring for PM, units using PM 

CEMS will not be required to conduct 

parameter monitoring for PM. 

This final rule also includes an 

alternative method of demonstrating 

continuous compliance with the HCl 

emission limit. This method allows 

using SO2 emissions as an alternate 

operating limit. This method of 

demonstrating continuous compliance 

will be allowed only on a unit that 

utilizes a SO2 CEMS and an acid-gas 

control technology including wet 

scrubber, dry scrubbers and duct 

sorbent injection. Boilers or process 

heaters subject to an HCl emission limit 

that demonstrate compliance with an 

SO2 CEMS would be required to 

maintain the 30-day rolling average SO2

emission rate at or below the highest 

hourly average SO2 concentration 

measured during the most recent HCl 

performance test. 

G. What are the compliance dates? 

For existing sources, the EPA is 

establishing a compliance date of 

January 31, 2016. New sources must 

comply by January 31, 2013, or upon 

startup, whichever is later. New sources 

are defined as sources which 

commenced construction or 

reconstruction on or after June 4, 2010 

pursuant to section 112(a)(4). 

Commenters have argued that the 3- 

year compliance deadline the EPA is 

establishing for existing sources to meet 

the standards does not provide them 

with sufficient time to meet the 

standards in view of the large number 

of sources that will be competing for the 

needed resources and materials from 

engineering consultants, permitting 

authorities, equipment vendors, 

construction contractors, financial 

institutions, and other critical suppliers. 

As an initial matter, we note that 

many sources subject to the emission 

standards in the final rule should be 

able to meet the standards within three 

years, even those that need to install 

pollution control technologies to do so. 

In addition, many sources subject to the 

rule are gas fired units or small boilers 

(less than 10 MMBtu/hr) and will not 

need to install controls in order to 

demonstrate compliance, as these 

sources are subject to work practice 

standards. For these sources, the 3-year 

compliance deadline is highly unlikely 

to be problematic either in general, or 

with respect to the claims commenters 

have made about the possibility that the 

demand for resources related to control 

technology will exceed the supply. 

At the same time, the CAA allows title 

V permitting authorities to grant 

sources, on a case-by-case basis, 

extensions to the compliance time of up 

to one year if such time is needed for 

the installation of controls. See CAA 

section 112(i)(4)(i)(A). Permitting 

authorities are already familiar with, 

and in many cases have experience 

with, applying the 1-year extension 

authority under section 112(i)(4)(A) 

since the provision applies to all 

NESHAP. We believe that should the 

range of circumstances that commenters 

have cited as impeding sources’ ability 

to install controls within three years 

materialize, then it is reasonable for 

permitting authorities to take those 

circumstances into consideration when 

evaluating a source’s request for a 1-year 

extension, and where such applications 

prove to be well-founded, it is also 

reasonable for permitting authorities to 

make the 1-year extension available to 

applicants. 

In making a determination as to 

whether an extension is appropriate, we 

believe it is also reasonable for 

permitting authorities to consider the 

large number of pollution control 

retrofit projects being undertaken for 

purposes of complying either with the 

standards in this rule or with those of 

other rules such as MATS for the power 

sector that may be competing for similar 

resources. 

Further, commenters have pointed out 

that in some cases operators of existing 

sources that are subject to these 

standards and that generate energy may 

opt to meet the standards by terminating 

operations at these sources and building 

new sources to replace the energy 

generation at the shut-down sources. 

While the ultimate discretion to provide 

a 1-year extension lies with the 

permitting authority, the EPA believes 

that it is reasonable for permitting 

authorities to allow the fourth year 

extension for the installation of 

replacement sources of energy 

generation at the site of a facility 

applying for an extension for that 

purpose. Specifically, the EPA believes 

where an applicant demonstrates that it 

is building replacement sources of 

energy generation for purposes of 

meeting the requirements of these 

standards such a replacement project 

could be deemed to constitute the 

‘‘installation of controls’’ under section 

112(i)(3)(B). 

In a case where pollution controls are 

being installed or onsite replacement 

energy generation is being constructed 

to allow for retirement of older, undercontrolled energy generation units, a 

determination that an extra year is 

necessary for compliance should be 

relatively straightforward. In order to 

install controls, companies are likely to 

undertake a number of steps relatively 

soon after the effective date of the rule, 

including obtaining necessary building 

and environmental permits and hiring 

contractors to perform the construction 

of the emission controls or replacement 

energy generation units. This should 

provide sufficient information for a 

permitting authority to determine that 

emission controls are being installed or 

that replacement energy generation is 

being constructed. As a result, a 

permitting authority will be in a 

position to make a determination as to 

whether a source’s compliance schedule 

will exceed 3 years and to quickly make 

a determination as to when an extension 

is appropriate. 

In sum, the EPA believes that 

although most, if not all, units will be 

able to fully comply with the standards 

within 3 years, the fourth year that 

permitting authorities are allowed to 

grant for installation of controls is an 

important flexibility that will address 

situations where an extra year is 

necessary. Of course in situations where 

EPA is the permitting authority, we 

would also consider the above 

circumstances when acting on a permit 

application. 

IV. Summary of Significant Changes 

Since Proposal 

The EPA has made numerous changes 

in this final rule from the proposal after 

consideration of the public comments 

received. Most are changes to clarify 

applicability and implementation issues 

raised by the commenters. The public 

comments received on the proposed 

changes and the responses to them can 

be viewed in the memorandum 

‘‘Response to Comments for Industrial, 

Commercial, and Institutional Boilers 


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7144 Federal Register / Vol. 78, No. 21 / Thursday, January 31, 2013 / Rules and Regulations 

and Process Heaters National Emission 

Standards for Hazardous Air Pollutants’’ 

located in the docket. 

A. Applicability 

Since proposal, the EPA has made 

certain changes to the applicability of 

this final rule. We have clarified that the 

exemption for boilers and process 

heaters used for research and 

development includes boilers used for 

testing the propulsion systems on 

military vessels. This is consistent with 

the intent of the exemption in that these 

test boilers do not provide steam for 

heating, to a process, or other nonpropulsion related uses but are used 

exclusively to test the propulsion 

systems of nuclear-powered aircraft 

carriers that are undergoing repair, 

overhaul, or installation. 

B. Subcategories 

As described in the preamble to the 

proposed reconsideration rule, within 

the basic unit types of boilers and 

process heaters there are different 

designs and combustion systems that, 

while having a minor effect on fueldependent HAP emissions, have a much 

larger effect on pollutants whose 

emissions depend on the combustion 

conditions in a boiler or process heater. 

In the case of boilers and process 

heaters, the combustion-related 

pollutants are the organic HAP. In the 

proposed rule, we identified the 

following 17 subcategories for organic 

HAP: (1) Pulverized coal units; (2) 

stokers designed to burn coal; (3) 

fluidized bed units designed to burn 

coal; (4) stokers designed to burn wet 

biomass; (5) stokers designed to burn 

kiln-dried biomass; (6) fluidized bed 

units designed to burn biomass; (7) 

suspension burners designed to burn 

biomass; (8) dutch ovens/pile burners 

designed to burn biomass; (9) fuel cells 

designed to burn biomass; (10) hybrid 

suspension grate units designed to burn 

biomass; (11) units designed to burn 

heavy liquid fuel; (12) units designed to 

burn light liquid fuel; (13) noncontinental liquid units; (14) units 

designed to burn natural gas/refinery 

gas; (15) units designed to burn other 

gases; (16) metal process furnaces; and 

(17) limited-use units. 

In this final rule, we are also adding 

a separate subcategory for fluidized bed 

units with a fluidized bed heat 

exchanger designed to burn coal and 

adjusted the definition of the limited 

use subcategory. 

Fluidized bed boilers are designed to 

combust fuel with relatively low heating 

value and high ash compared to other 

combustor designs. Two fuel properties 

of coal are heating values and ash 

content. As the heating value of the coal 

decreases, ash content increases. 

Fluidized bed boilers are designed to 

have large tube surface areas to transfer 

heat from the fuel through the process 

of conduction and convection, but in 

some cases the amount of tube surface 

area in the furnace for heat transfer is 

insufficient. In order to overcome 

insufficient heat exchange, certain 

fluidized bed boilers adopt a fluidized 

bed heat exchanger design to achieve 

heat transfer. The fluidized bed heat 

exchanger is located at the exit of the 

cyclone section of the unit. This design 

allows the boiler to combust coal with 

a lower heating value than a coal-fired 

fluidized bed boiler without a fluidized 

bed heat exchanger. Therefore, because 

this boiler design does have different 

combustion-related HAP emission 

characteristics, a new subcategory of 

coal fluidized bed with integrated heat 

exchanger was added to the final rule. 

The EPA is also revising the 

definition of the limited use 

subcategory. Many affected units 

operate on standby mode or low loads 

for periods longer than the proposed 

definition for limited use units, which 

limited operation to 876 hours per year. 

By converting to a capacity-factor 

approach, we are allowing more 

flexibility on unit operations without 

increasing emissions or harm to human 

health and the environment. For 

example, units operating at 10 percent 

load for 8,760 hours per year would 

emit the same amount of emissions as 

units operating at full load for 876 hours 

per year. Further, it is technically 

infeasible to schedule stack testing for 

these limited use units since these units 

serve as back up energy sources and 

their operating schedules can be 

intermittent and unpredictable. The 

limited use subcategory was adjusted to 

be based on units with a federally 

enforceable operating limit of less than 

or equal to 10 percent of an average 

annual capacity factor. 

C. Performance Test Requirements 

Table 5 of this final rule has been 

revised to add performance test 

procedures for conducting performance 

stack tests for demonstrating 

compliance with the alternate TSM 

emission limits. In the reconsideration 

proposal, we proposed emissions limits 

for TSM (i.e., arsenic, beryllium, 

cadmium, chromium, lead, manganese, 

nickel and selenium) as an alternative to 

the proposed PM emission limits for 

many of the subcategories. In the 

preamble to the proposed rule, we 

added procedures in Table 6 of the rule 

for conducting fuel analysis for total 

selected metals but we inadvertently 

failed to add performance test 

requirements for stack sampling of TSM 

emissions in Table 5 of the rule. 

D. Emission Limits 

One significant change since proposal 

is related to the PM emission limits for 

the coal subcategories. Several 

petitioners disagreed with EPA’s 

position to set different PM limits for 

subcategories of boilers and process 

heaters based on the fuel used, and 

instead offered information to support 

the position that PM should be 

considered a combustion-based 

pollutant. The differences in PM 

particle size, fouling characteristics and 

feasibility of certain control 

technologies on certain unit designs 

suggested that PM is more appropriately 

classified as a combustion-based 

pollutant, but only for the coal 

subcategories. After assessing the points 

raised by the petitioners, the EPA agreed 

that PM emissions are influenced by 

unit design, and fuel type, and proposed 

to create combustion-based pollutant 

subcategories for coal and solid fuels 

and create fuel-based subcategories for 

liquid and biomass fuel units. The EPA 

is finalizing a single PM limit for all 

coal/solid fossil fuel subcategories, and 

is also finalizing emissions limits based 

on PM as a combustion-based pollutant 

for the biomass and liquid fuel 

subcategories. 

Another change from proposal is that 

the alternative TSM emission limits are 

now applicable to the three liquid fuel 

subcategories. Several commenters 

provided data and comments supporting 

these alternative emission standards for 

non-mercury metallic HAP. After 

assessing the revised data and the points 

made by the commenters, the EPA 

agrees that the limited data available for 

liquid fuel units are not unique to this 

subcategory. Based on the EPA agreeing 

with the commenters, the EPA recalculated the TSM emission limits for 

the liquid fuel subcategories and 

included them in the final rule. 

The CO emission limit for several 

subcategories, both new and existing, 

have been revised to reflect a CO level 

that is consistent with MACT for 

organic HAP reduction. Several 

commenters recommended that the EPA 

evaluate a minimum CO standard (i.e., 

100 ppm corrected to 7 percent oxygen) 

to serve as a lower bound surrogate for 

organic HAP. Commenters also 

provided data and information to 

support such a standard, and noted that 

the EPA has taken a similar approach in 

other emission standards under section 

112. 

The EPA evaluated whether there is a 

minimum CO level for boilers and 


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process heaters below which there is no 

further benefit in organic HAP 

reduction/destruction. Specifically, we 

evaluated the relationship between CO 

and formaldehyde using the available 

data obtained during the rulemaking. 

Formaldehyde was selected as the basis 

of the organic HAP comparison because 

it is the most prevalent organic HAP in 

the emission database and a large 

number of paired tests existed for 

boilers and process heaters for CO and 

formaldehyde. The paired data show 

decreasing formaldehyde emissions 

with decreasing CO emissions down to 

CO levels around 300 ppm, supporting 

the selection of CO as a surrogate for 

organic HAP emissions. A slight 

increase in formaldehyde emissions is 

observed at CO levels below around 200 

ppm, suggesting a breakdown in the COformaldehyde relationship at low CO 

levels. At levels lower than 150 ppm, 

the mean levels of formaldehyde appear 

to increase, as does the overall 

maximum value of and variability in 

formaldehyde emissions. However, we 

are aware of no reason why CO 

concentrations would continue to 

decrease and formaldehyde 

concentrations would increase as 

combustion conditions improve. It is 

possible that imprecise formaldehyde 

measurements at low concentrations 

(i.e., 1–2 ppm) may account for this 

slight increase in formaldehyde 

emissions observed at CO levels below 

100 ppm corrected to 7 percent oxygen. 

Based on this, we do not believe that 

such measurements are sufficiently 

reliable to use as a basis for establishing 

an emissions limit. 

Therefore, based on the above 

analysis, we are promulgating a 

minimum MACT floor level for CO of 

130 ppm corrected to 3 percent oxygen 

(which is equivalent to 100 ppm 

corrected to 7 percent oxygen). We note 

this is the same approach used to 

establish the CO emission limit of 100 

ppm corrected to 7 percent oxygen for 

the Burning of Hazardous Waste in 

Boilers and Industrial Furnaces rule. 

Additional discussion of the rationale 

for this approach can be found in the 

memorandum ‘‘Revised MACT Floor 

Analysis (August 2012) for Industrial, 

Commercial, Institutional Boilers and 

Process Heaters National Emission 

Standards for Hazardous Air 

Pollutants—Major Source.’’ 

Subcategories where the initial MACT 

floor 99 percent UPL calculations for CO 

were less than 100 ppm corrected to 7 

percent oxygen (or equivalently 130 

ppm corrected to 3 percent oxygen) are 

as follows: 

• New and Existing Subcategories: 

Coal-FB, Coal-PC, Heavy Liquid, Light 

Liquid, Non-Continental Liquid, Process 

Gas 

• New Subcategories: Coal-Stoker 

We believe a CO level of 130 ppm 

corrected to 3 percent oxygen is an 

appropriate minimum MACT floor 

level. Although some measurements 

show CO levels below 130 ppm 

corrected to 3 percent oxygen, it is not 

appropriate to establish a lower floor 

level because CO is a conservative 

surrogate for organic HAP. In other 

words, organic HAP emissions are 

extremely low when sources operate 

under the good combustion conditions 

required to achieve CO levels in the 

range of zero to 100 ppm. As such, 

lowering the CO floor below 100 ppm 

will not provide reductions in organic 

HAP emissions. There are myriad 

factors that affect combustion efficiency 

and, as a function of combustion 

efficiency, CO emissions. As 

combustion conditions improve and 

hydrocarbon levels decrease, the larger 

and easier to combust compounds are 

oxidized to form smaller compounds 

that are, in turn, oxidized to form CO 

and water. As combustion continues, 

CO is then oxidized to form carbon 

dioxide and water. Because CO is a 

difficult to destroy refractory compound 

(i.e., oxidation of CO to carbon dioxide 

is the slowest and last step in the 

oxidation of hydrocarbons), it is a 

conservative surrogate for destruction of 

hydrocarbons, including organic HAP. 

The conservative nature of CO as an 

indicator of good combustion practices 

is supported by our data. At CO levels 

less than 100 ppm corrected to 7 percent 

oxygen, our data indicate that there is 

no apparent relationship between CO 

and organic HAP (i.e., formaldehyde). 

For example, a source with a CO level 

of 20 ppm may have the same measured 

formaldehyde as a source achieving a 

CO emission level of 100 ppm corrected 

to 7 percent oxygen. Sources are 

required to establish operating 

requirements based on operating levels 

that were demonstrated during the test. 

Sources must comply with these 

operating requirements on a continuous 

basis. Compliance with these 

requirements adequately assures sources 

will be controlling organic HAP 

emissions to MACT levels. 

As detailed in the docketed 

memorandum ‘‘Beyond the Floor 

Technology Analysis for Major Source 

Boilers and Process Heaters (Revised 

August 2012),’’ we reviewed the 

emission limits that are becoming less 

stringent since the March 2011 final rule 

in order to assess whether a beyond the 

floor option was technically achievable 

and cost effective. As a result of this 

review, the PM emission limits for 

several new biomass subcategories have 

been changed to reflect a beyond the 

floor limit of 0.03 lb/MMBtu, based on 

the limit for new biomass boilers in 40 

CFR part 60 subparts Db and Dc. Due to 

the low mercury emission limits for new 

solid fuel boilers, these new biomass 

units are expected to install a fabric 

filter level of control in order to meet 

the new source mercury limits for the 

solid fuel subcategory. This mercury 

control has the co-benefit of reducing 

PM emissions down to levels of 0.03 lb/ 

MMBtu so there is no incremental cost 

to achieve these additional reductions 

in PM for the biomass units that have a 

design heat input capacity between 10 

and 30 MMBtu/hr. For units with a 

design heat input capacity of 30 

MMBtu/hr or greater, these units are 

already subject to a PM limit of 0.03 lb/ 

MMBtu and adjusting these new source 

limits to this level of control makes the 

limits consistent between both rules, 

without adding additional costs. We did 

not identify any beyond the floor 

options for existing source PM limits or 

new and existing limits for other 

pollutants as technically feasible or cost 

effective. 

The other changes associated with the 

other emission limits are due to new 

data, corrections to old data, and 

inventory changes. In summary, 

compared to the December 23, 2011 

proposed limits for existing units, the 

final HCl emission limits remained the 

same; for the final mercury emission 

limits, 3 are more stringent, 10 are less 

stringent and 1 is unchanged; for the 

final PM emission limits, 3 are more 

stringent, 5 are less stringent and 6 are 

unchanged; and for the final CO 

emission limits, 3 are more stringent 

and 11 are less stringent. For new units, 

compared to the proposed emission 

limits, 3 of the final HCl emission limits 

are more stringent and 11 remained the 

same; for the final mercury emission 

limits, 10 are more stringent and 4 are 

unchanged; for the final PM emission 

limits, 5 are more stringent, 2 are less 

stringent and 7 are unchanged; and for 

the final CO emission limits, 2 are more 

stringent, 11 are less stringent and 1 is 

unchanged. 

E. Work Practice Requirement 

In this final rule several changes have 

been made to the work practice 

requirement to conduct a tune-up. First, 

the requirement to inspect the burner 

has been revised to allow units that sell 

electricity to schedule the burner 

inspection, as well as the air-to-fuel 

system inspection, at the time of the 

first outage but not to exceed 36 months 

from the previous inspection. This 


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change is being made to this final rule 

because commenters stated that large 

boilers that serve electricity for sale may 

not require annual outages and would, 

therefore, need to be taken off-line for 

the sole purpose of an annual tune-up. 

This frequency is consistent with the 

requirements of the NESHAP for electric 

utility boilers (40 CFR part 63, subpart 

UUUUU). 

Also, for units where entry into a 

piece of process equipment or into a 

storage vessel is required to complete 

the tune-up inspections, inspections are 

required only during planned entries 

into the storage vessel or into process 

equipment. Commenters indicated that 

some process heaters are installed 

inside tanks and entry into the tank to 

access the heater may not occur within 

a 5 year period. 

The requirement to optimize total 

emissions of CO has been revised to 

require that this optimization not only 

be consistent with the manufacturer’s 

specifications but also with any NOX

emission requirement to which the unit 

is subject. Some commenters indicated 

that many boilers need different tune-up 

criteria due to their requirement to also 

comply with low NOX emission limits. 

We are also aware that several states 

have boiler tune-up requirements to 

minimize NOX emissions first and then 

optimize CO emissions. 

We have added boilers or process 

heaters that have a continuous oxygen 

trim system to the types of boilers or 

process heaters that must conduct a 

tune-up every 5 years. These units do 

not need to be tuned as frequently 

because the trim system is designed to 

continuously measure and maintain an 

optimum air to fuel ratio which is the 

purpose of a tune-up. 

F. Averaging Times Definitions 

We revised the definitions of ‘‘30-day 

rolling average’’ and ‘‘daily block 

average’’ to exclude periods of startup 

and shutdown or downtime from the 

arithmetic mean. Commenters requested 

that the EPA specify how a 30-day 

rolling average is calculated and 

whether it includes the previous 720 

hours of valid operating data and that 

the valid data exclude hours during 

startup and shutdown as well as unit 

down time. We agree with the 

commenters that the definitions need 

clarification and that these periods 

should not be included in calculating 

the 30-day rolling average. Therefore, 

we have revised the definitions 

accordingly. 

We have also included in the final 

rule a definition of ‘‘10-day rolling 

average’’ that is consistent with the 

revised definition of ‘‘30-day rolling 

average.’’ 

G. Energy Assessment 

In this final rule, we have revised the 

definition of energy assessment per the 

requirements of Table 3 of this final rule 

by providing duration for performing 

the energy assessment for large fuel use 

facilities. In numbered paragraph (3) in 

the definition of ‘‘Energy assessment’’ in 

§ 63.7575, which is for facilities with 

units having a combined heat input 

capacity greater than 1 TBtu/yr, we 

added time duration/size ratio and 

included a cap to the maximum number 

of on-site technical hours that should be 

used in the energy assessment. This 

addition of a duration for large fuel use 

facilities is being made to be consistent 

with durations specified for small 

[paragraph (1) in the definition of 

‘‘Energy assessment’’] and medium 

[paragraph (2) in the definition of 

‘‘Energy assessment’’] fuel use facilities. 

The energy assessment for facilities with 

affected boilers and process heaters 

having a combined heat input capacity 

greater than 1.0 TBtu/yr will be up to 24 

on-site technical labor hours for the first 

TBtu/yr plus 8 technical labor hours for 

every additional 1.0 TBtu/yr not to 

exceed 160 technical hours, but may be 

longer at the discretion of the owner or 

operator. 

The revised definition of energy 

assessment also clarifies our intentions 

that the scope of assessment is based on 

energy use by discrete segments of a 

facility and not by a total aggregation of 

all individual energy using elements of 

a facility. The applicable discrete 

segments of a facility could vary 

significantly depending on the site and 

its complexity. We have added the 

following paragraph (4), to the energy 

assessment definition to help resolve 

current problems in identifying the 

scope of the various energy use systems 

in a large industrial complex and allow 

for more streamlined assessments: 

‘‘(4) The on-site energy use systems 

serving as the basis for the percent of 

affected boiler(s) and process heater(s) 

energy output in (1), (2) and (3) above 

may be segmented by production area or 

energy use area as most logical and 

applicable to the specific facility being 

assessed (e.g., product X manufacturing 

area; product Y drying area; Building 

Z).’’ 

We have also revised paragraph 4 of 

Table 3 of the final rule to allow a 

source that is operating under an energy 

management program established 

through energy management systems 

compatible with ISO 50001, which 

includes the affected units, to satisfy the 

energy assessment requirement. We 

consider these energy management 

programs to be equivalent to the onetime energy assessment because 

facilities having these programs operate 

under a set of practices and procedures 

designed to manage energy use on an 

ongoing basis. These programs contain 

energy performance measurements and 

tracking plans with periodic reviews. 

The definition of ‘‘Energy use system’’ 

has also been revised in this final rule 

to clarify that energy use systems are 

only those systems using energy clearly 

produced by affected boilers and 

process heaters. 

H. Startup and Shutdown Definitions 

A number of commenters indicated 

that the proposed load specifications 

(i.e., 25 percent load) within the 

definitions of ‘‘startup’’ and 

‘‘shutdown’’ were inconsistent with 

either safe or normal (proper) operation 

of the various types of boilers and 

process heaters encountered within the 

source category. As the basis for 

defining periods of startup and 

shutdown, a number of commenters 

suggested alternative load specifications 

based on the specific considerations of 

their boilers; other commenters 

suggested the achievement of various 

steady-state conditions. 

We have reviewed these comments 

and believe adjustments are appropriate 

in the definition of ‘‘startup’’ and 

‘‘shutdown.’’ These adjustments are 

tailored for industrial boilers and are 

consistent with the definitions of 

‘‘startup’’ and ‘‘shutdown’’ contained in 

the 40 CFR part 63, subpart A General 

Provisions. We believe these revised 

definitions address the comments and 

are rational based on the fact that 

industrial boilers function to provide 

steam or, in the case of cogeneration 

units, electricity; therefore, industrial 

boilers should be considered to be 

operating normally at all times steam of 

the proper pressure, temperature, and 

flow rate is being supplied to a common 

header system or energy user(s) for use 

as either process steam or for the 

cogeneration of electricity. The 

definitions of ‘‘startup’’ and 

‘‘shutdown’’ have been revised in the 

final rule as follows: 

‘‘Startup means either the first-ever 

firing of fuel in a boiler or process 

heater for the purpose of supplying 

steam or heat for heating and/or 

producing electricity, or for any other 

purpose, or the firing of fuel in a boiler 

or process heater after a shutdown event 

for any purpose. Startup ends when any 

of the steam or heat from the boiler or 

process heater is supplied for heating 

and/or producing electricity, or for any 

other purpose.’’ 


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‘‘Shutdown means the cessation of 

operation of a boiler or process heater 

for any purpose. Shutdown begins 

either when none of the steam and heat 

from the boiler or process heater is 

supplied for heating and/or producing 

electricity, or for any other purpose, or 

at the point of no fuel being fired in the 

boiler or process heater, whichever is 

earlier. Shutdown ends when there is 

both no steam or heat being supplied 

and no fuel being fired in the boiler or 

process heater.’’ 

The EPA is requiring sources to vent 

emissions to the main stack(s) and 

operate all control devices necessary to 

meet the normal operating standards 

under this final rule (with the exception 

of limestone injection in FBC boilers, 

dry scrubber, fabric filter, SNCR and 

SCR) when firing coal/solid fossil fuel, 

biomass/bio-based solids, heavy liquid 

fuel or gas 2 (other) gases in the boiler 

or process heater during startup or 

shutdown. It is the responsibility of the 

operators of affected boilers and process 

heaters to start their limestone injection 

in FBC boilers, dry scrubber, fabric 

filter, SNCR and SCR systems 

appropriately to comply with relevant 

standards applicable during normal 

operation. Startup ends and normal 

operating standards apply when heat or 

steam is supplied for any purpose. 

The EPA carefully considered fuels 

and potential operational constraints of 

APCD when designing its work 

practices for periods of startup and 

shutdown. The EPA notes that there is 

no technical barrier to burning clean 

fuels (e.g., natural gas, distillate oil) for 

longer portions of startup or shutdown 

periods at a boiler and the HAP 

emission reduction benefits warrant 

additional utilization of such fuels until 

the temperature and stack emissions 

pressure is sufficient to engage the 

APCD. The EPA is aware that SNCR and 

SCR systems with ammonia injection 

need to be operated within a prescribed 

and relatively narrow temperature 

window to provide NOX reductions. 

Further, the EPA is aware that dry 

scrubbers also need to be operated close 

to flue gas saturation temperature, and 

that fabric filters need to be operated at 

temperatures above the acid dew point. 

Because these devices have specific 

temperature requirements for proper 

operation, the EPA notes in its work 

practices that it is the responsibility of 

the operators of affected boilers and 

process heaters to start their SNCR, SCR, 

fabric filter and dry scrubber systems 

appropriately to comply with relevant 

standards applicable during normal 

operation. 

I. Fuel Sampling Frequency 

The sampling frequency for gaseous 

fuel-fired units that elected to 

demonstrate that the unit meets the 

specification for mercury for the unit 

designed to burn gas 1 subcategory has 

been revised in this final rule. If the 

initial mercury constituents in the 

gaseous fuels are measured to be equal 

to or less than half of the mercury 

specification, no further sampling is 

required. If the initial mercury 

constituents are greater than half but 

equal to or less than 75 percent of the 

mercury specification, only semi-annual 

sampling need to be conducted. If the 

initial mercury constituents are greater 

than 75 percent of the mercury 

specification, monthly sampling is 

required. 

J. Affirmative Defense 

In the proposal, we used terms such 

as ‘‘exceedance’’ or ‘‘excess emissions’’ 

in § 63.7501, which created unnecessary 

confusion as to when the affirmative 

defense could be used. In the final 

amended rule, we have eliminated those 

terms and used the word ‘‘violation’’ to 

make clear that the affirmative defense 

to civil penalties is available only where 

an event that causes a violation of the 

emissions standard meets the definition 

of malfunction under § 63.2. 

We have also eliminated the 2-day 

notification requirement that was 

included in 40 CFR 63.7501(b) at 

proposal because we expect to receive 

sufficient notification of malfunction 

events that result in violations in other 

required compliance reports, such as the 

malfunction report required under 40 

CFR 63.7550(c). In addition, we have 

revised the 45-day affirmative defense 

reporting requirement that was included 

in 40 CFR 63.7501(b) at proposal to 

require sources to include the report in 

the first compliance, deviation or excess 

emission report due after the initial 

occurrence of the violation, unless the 

compliance, deviation or excess 

emission report is due less than 45 days 

after the violation. In that case, the 

affirmative defense report may be 

included in the second compliance, 

deviation or excess emission report due 

after the initial occurrence of the 

violation. Because the affirmative 

defense report is now included in a 

subsequent compliance, deviation or 

excess emission report, there is no 

longer a need for the proposed 30-day 

extension for submitting a stand-alone 

affirmative defense report. 

Consequently, we are not including this 

provision in the final amended rule. We 

have also re-evaluated the language 

concerning the use of off-shift and 

overtime labor to the extent practicable 

and believe that the language is not 

necessary. Thus, we have deleted that 

phrase from section 63.7501(a)(2). 

V. Other Actions We Are Taking 

Section 307(d)(7)(B) of the CAA states 

that ‘‘[o]nly an objection to a rule or 

procedure which was raised with 

reasonable specificity during the period 

for public comment (including any 

public hearing) may be raised during 

judicial review. If the person raising an 

objection can demonstrate to the 

Administrator that it was impracticable 

to raise such objection within such time 

or if the grounds for such objection 

arose after the period for public 

comment (but within the time specified 

for judicial review) and if such objection 

is of central relevance to the outcome of 

the rule, the Administrator shall 

convene a proceeding for 

reconsideration of the rule and provide 

the same procedural rights as would 

have been afforded had the information 

been available at the time the rule was 

proposed. If the Administrator refuses to 

convene such a proceeding, such person 

may seek review of such refusal in the 

United States court of appeals for the 

appropriate circuit (as provided in 

subsection (b)).’’ 

As to the first procedural criterion for 

reconsideration, a petitioner must show 

why the issue could not have been 

presented during the comment period, 

either because it was impracticable to 

raise the issue during that time or 

because the grounds for the issue arose 

after the period for public comment (but 

within 60 days of publication of the 

final action). The EPA is denying the 

petitions for reconsideration on a 

number of issues because this criterion 

has not been met. In many cases, the 

petitions reiterate comments made on 

the proposed June 2011 rule during the 

public comment period for that rule. On 

those issues, the EPA responded to 

those comments in the final rule and 

made appropriate revisions to the 

proposed rule after consideration of 

public comments received. It is wellestablished that an agency may refine its 

proposed approach without providing 

an additional opportunity for public 

comment. See Community Nutrition 

Institute v. Block, 749 F.2d at 58 and 

International Fabricare Institute v. EPA, 

972 F.2d 384, 399 (D.C. Cir. 1992) 

(notice and comment is not intended to 

result in ‘‘interminable back-andforth[,]’’ nor is agency required to 

provide additional opportunity to 

comment on its response to comments) 

and Small Refiner Lead Phase-Down 

Task Force v. EPA, 705 F.2d 506, 547 

(D.C. Cir. 1983) (‘‘notice requirement 


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should not force an agency endlessly to 

repropose a rule because of minor 

changes’’) 

In the EPA’s view, an objection is of 

central relevance to the outcome of the 

rule only if it provides substantial 

support for the argument that the 

promulgated regulation should be 

revised. See Union Oil v. EPA, 821 F.2d 

768, 683 (D.C. Cir. 1987) (court declined 

to remand rule because petitioners 

failed to show substantial likelihood 

that final rule would have been changed 

based on information in petition). See 

also the EPA’s Denial of the Petitions to 

Reconsider the Endangerment and 

Cause or Contribute Findings for 

Greenhouse Gases under Section 202 of 

the Clean Air Act, 75 FR at 49556, 49561 

(August 13, 2010). See also, 75 FR at 

49556, 49560–49563 (August 13, 2010) 

and 76 FR at 4780, 4786–4788 (January 

26, 2011) for additional discussion of 

the standard for reconsideration under 

CAA section 307(d)(7)(B). 

We are denying reconsideration on 

the following 57 issues contained in the 

petitions for reconsideration because 

they failed to meet the standard 

described above for reconsideration 

under CAA section 307(d)(7)(B). 

Specifically, on these issues, the 

petitioner has failed to show the 

following: that it was impracticable to 

raise their objections during the 

comment period or that the grounds for 

their objections arose after the close of 

the comment period; and/or that their 

concern is of central relevance to the 

outcome of the rule. Therefore, the EPA 

is denying the petitions for 

reconsideration on the issues for the 

reasons described below. 

Issue: Delist gas units. 

The petitioners (API, NPRA) 

requested that the EPA remove gas-fired 

units from the section 112(c) list of 

source categories for which the EPA is 

required to establish emissions 

standards under section 112(d). The 

EPA is denying the petition for 

reconsideration for the following 

reasons. First, the issue is outside the 

scope of this rulemaking, which 

establishes emissions standards for new 

and existing units within the major 

source boilers and process heaters 

source category. The EPA did not solicit 

comment in the proposed rule regarding 

the scope of the subcategory. Further, 

petitioners provide no information to 

support delisting gas units under 

section 112(c)(9), which requires the 

EPA to make certain findings before 

delisting any sources. In addition, the 

petition does not address the D.C. 

Circuit’s decision in NRDC v. EPA, 489 

F.3d 1364 (2007), regarding the EPA’s 

ability to delist subcategories of a source 

category pursuant to section 112(c)(9). 

For these reasons, the petitions do not 

provide support for the argument that 

the regulation should be changed. For 

this reason, the petition does not 

demonstrate that the issue is of central 

relevance to the outcome of the final 

rule and the EPA is denying the request 

for reconsideration. 

Issue: Exempt natural gas hot water 

heaters with tanks greater than 120 

gallons. 

The petitioner (AIF) requested that 

the EPA exempt natural gas hot water 

heaters with tanks greater than 120 

gallons. While the EPA disagrees with 

the petitioner regarding whether such 

units should be subject to the emissions 

standards in this rule, the petitioner has 

not demonstrated that it lacked the 

opportunity to comment on whether 

such units should be required to meet 

emissions standards. The EPA proposed 

work practice standards for such units 

in its June 2010 proposal, and the 

petitioner had the opportunity to 

comment on whether such standards 

should be applied to such units at all. 

Therefore, the EPA is denying the 

request for reconsideration. 

Issue: Exempt natural gas and 

distillate oil-fired circulating hot water 

systems with a design capacity of 10 

MMBtu/hr or less. 

The petitioner (CIBO) requested that 

the EPA exempt natural gas and 

distillate oil-fired circulation hot water 

systems that are not greater than 10 

MMBtu/hr. While the EPA disagrees 

with the petitioner regarding whether 

such units should be subject to the 

emissions standards in this rule, the 

petitioner has not demonstrated that it 

lacked the opportunity to comment on 

whether such units should be required 

to meet emissions standards. The EPA 

proposed emissions standards for such 

units, and the petitioner had the 

opportunity to comment on whether 

such standards should be applied to 

such units at all. In addition, the 

petition does not provide any 

information to demonstrate that these 

units should be delisted pursuant to 

section 112(c)(9). Therefore, the EPA is 

denying the request for reconsideration. 

Issue: Confirm in definitions that 

open flame heaters (e.g., asphalt tank 

heaters) are not process heaters. 

The petitioners (API, NPRA) 

requested that the EPA clarify in the 

definition of ‘‘process heater’’ that open 

flame heaters do not meet the definition. 

While the EPA disagrees with the 

petitioners whether clarification is 

needed in regards to open flame heaters, 

the petitioners have not demonstrated 

that it lacked the opportunity to 

comment on the proposed definition. 

The definition that the EPA proposed 

clearly states that process heaters are 

enclosed devices in which the 

combustion gases do not come into 

contact with process materials, and as 

such, does not include open flame 

heaters. Therefore, the EPA is denying 

reconsideration. 

Issue: For blast furnace fuel-fired 

boiler exemption, compute the 90 

percent BFG by volume threshold to 

exclude periods of BFG curtailment. 

The petitioners (AISI, ACCCI) 

requested that the EPA revise the 

exemption for BFG fuel-fired boilers to 

exclude periods of BFG curtailment. 

While the EPA disagrees with the 

petitioners regarding revising the 

exemption, the petitioners have not 

demonstrated that it lacked the 

opportunity to comment on the 

proposed exemption for BFG fuel-fired 

boilers. The EPA proposed the 

exemption for these boilers, and 

petitioners therefore had the 

opportunity to comment on whether the 

exemption should apply to periods of 

BFG curtailment. Therefore, the EPA is 

denying the request for reconsideration. 

Issue: Exempt boilers whose flue gases 

are used in direct-fired process heaters 

subject to other NESHAP. 

The petitioner (CMI) requested that 

the EPA exempt from the rule boilers 

whose flue gases are used in direct-fired 

process heaters that are subject to other 

NESHAP. The final rule does not apply 

to such units if they are subject to 

another NESHAP. The EPA does not see 

a need for further clarification. Since the 

final rule does in fact exempt these 

units, the EPA is denying the request for 

reconsideration. 

Issue: Work practice standards do not 

meet EPA obligations under 112(c)(6). 

The petitioner (Sierra Club) requested 

that the EPA establish numeric 

emissions limits for Gas 1 units rather 

than work practice standards. 

Specifically, the petitioner alleges that 

the work practice standards do not meet 

the EPA’s obligations under section 

112(c)(6) of the CAA, and that it was not 

the case that data were below the 

detection level for all HAP emitted from 

these units. The EPA is denying the 

request for reconsideration on this issue. 

While the EPA disagrees with the 

petitioner’s arguments regarding the 

legal authority to establish work 

practice standards for Gas 1 units and 

the basis for such standards, the 

petitioner has not demonstrated that it 

lacked the opportunity to comment on 

this issue. The EPA proposed work 

practice standards for Gas 1 units and 

explained in the proposal its rationale 

for such standards, including the fact 

that a significant portion of the 


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emissions data were below the detection 

level. 75 FR at 32024–25. Therefore, the 

petitioner had the opportunity to 

comment on this issue, and did in fact 

submit comments regarding the EPA’s 

legal authority to establish work 

practice standards for Gas 1 units. 

Therefore, the EPA is denying 

reconsideration on this issue. 

Issue: Work practices for small units 

are not justified by 112(h) since small 

units were not given their own 

subcategory. 

The petitioner (Sierra Club) requested 

that the EPA require small units, those 

having a heat input capacity of less than 

10 MMBtu/hr, to meet numeric 

emissions limits rather than work 

practice standards. The EPA is denying 

the request for reconsideration on this 

issue because the petitioner has not 

demonstrated that it lacked the 

opportunity to comment on this issue. 

The EPA proposed work practice 

standards for these units and explained 

in the proposal its rationale for such 

standards. 75 FR at 32024–25. The EPA 

did in fact receive comments regarding 

the proposed standards, to which it 

responded in the final rule. 76 FR at 

15640. Moreover, the EPA notes that 

nothing in section 112(h) limits the 

EPA’s discretion to establish work 

practice standards to the establishment 

of such standards for an entire category 

or subcategory. Therefore, the EPA is 

denying the request for reconsideration. 

Issue: PM is not an adequate 

surrogate for non-mercury metallic 

HAP. 

The petitioner (Sierra Club) requested 

that the EPA remove the PM standard as 

a surrogate for non-mercury metallic 

HAP and instead adopt a numeric limit 

for non-mercury metallic HAP because 

PM is not an appropriate surrogate. The 

EPA is denying the request for 

reconsideration on this issue. While the 

EPA disagrees with the petitioner’s 

argument regarding the suitability of PM 

as a surrogate for non-mercury metallic 

HAP, the petitioner has not 

demonstrated that it lacked the 

opportunity to comment on this issue. 

The EPA proposed PM standards as a 

surrogate for non-mercury metallic HAP 

and explained in the proposal the 

agency’s basis for concluding that PM 

was an appropriate surrogate. 75 FR at 

32018. Therefore, the EPA is denying 

the request for reconsideration. 

Issue: Establish direct limits on 

organics or select a surrogate besides 

CO. 

The petitioner (Sierra Club) requested 

that the EPA remove the CO standard as 

a surrogate for organic HAP and instead 

adopt a numeric limit for these HAP, 

because CO is not an appropriate 

surrogate. The EPA is denying the 

request for reconsideration on this issue. 

While the EPA disagrees with the 

petitioner’s argument regarding the 

suitability of CO as a surrogate for 

organic HAP, the petitioner has not 

demonstrated that it lacked the 

opportunity to comment on this issue. 

The EPA proposed CO standards as a 

surrogate for organic HAP and 

explained in the proposal the agency’s 

basis for concluding that CO was an 

appropriate surrogate. 75 FR at 32018. 

The EPA received comments on this 

issue, including comments stating that 

CO is not an appropriate surrogate for 

organic HAP. Therefore, the EPA is 

denying the request for reconsideration. 

Issue: Adopt an alternative THC 

emission standard. 

The petitioner (CIBO) requested that 

the EPA adopt a THC emissions 

standard as an alternative to the CO 

standard. The EPA is denying the 

request for reconsideration on this issue. 

While the EPA disagrees with the 

petitioner’s argument regarding whether 

a THC alternative standard is 

appropriate as a surrogate for nondioxin organic HAP, the petitioner has 

not demonstrated that it lacked the 

opportunity to comment on this issue. 

The EPA raised in the proposal the 

possibility of THC as a surrogate for 

non-dioxin organic HAP, and explained 

why the use of CO as a surrogate was 

preferable. 75 FR at 32018. In addition, 

the EPA did not receive any comments 

or data during the public comment 

period on the proposed rule that would 

have enabled the agency to establish a 

THC alternative standard, including 

THC emissions data, nor did the 

petitioner provide any such data. 

Therefore, the petition does not provide 

substantial support for its argument that 

the final rule should be changed. For 

these reasons, the EPA is denying the 

petition for reconsideration on this 

issue. 

Issue: Regulation of Total dioxin/ 

furans exceeds statutory authority as 

only 2 compounds are in 112(b)(1). 

The petitioners (AISI, ACCCI, AF&PA) 

alleged that the EPA lacks statutory 

authority to regulate total dioxin/furans 

under CAA section 112, and that the 

EPA’s response in the final rule 

explaining why it is issuing a total 

dioxin/furan standard was not a logical 

outgrowth of the proposed rule. The 

EPA is denying the request for 

reconsideration on this issue. First, the 

EPA disagrees that the final rule is not 

a logical outgrowth of the proposal. The 

EPA proposed emissions standards for 

total dioxin/furans and adopted a final 

emissions standard for the same 

pollutant. Therefore, the commenter had 

the opportunity to provide its views 

during the public comment period 

regarding the EPA’s proposed emissions 

standard, including its views regarding 

the EPA’s authority to regulate the 

pollutant at issue. The fact that the EPA 

responded to those comments does not 

mean that the petitioner lacked the 

opportunity to comment—in fact, the 

petitioner did provide such comments. 

76 FR at 15640. For this reason, the EPA 

is denying the petition for 

reconsideration. 

Issue: HCl is an inadequate surrogate 

for all acid gases. 

The petitioner (Sierra Club) requested 

that the EPA remove the HCl standard 

as a surrogate for acid gases and instead 

adopt a numeric limit for these HAP, 

because HCl is not an appropriate 

surrogate. The EPA is denying the 

request for reconsideration on this issue. 

While the EPA disagrees with the 

petitioner’s argument regarding the 

suitability of HCl as a surrogate for acid 

gases, the petitioner has not 

demonstrated that it lacked the 

opportunity to comment on this issue. 

The EPA proposed HCl standards as a 

surrogate for acid gases and explained 

in the proposal the agency’s basis for 

concluding that HCl was an appropriate 

surrogate. 75 FR at 32018. While the 

EPA had emission data for HCl from 

hundreds of affected units upon which 

to establish standards, the EPA did not 

have sufficient data on the other acid 

gases to do so (hydrogen fluoride, 

hydrogen cyanide and chlorine). The 

petitioner did not refer to any such data 

and, therefore, the issue is not of central 

relevance to the outcome of the final 

rule. Therefore, the EPA is denying the 

request for reconsideration. 

Issue: Establish work practice for 

other organic HAP instead of using CO 

as a surrogate. 

The petitioners (AMP, JELD–WEN) 

requested that the EPA adopt a work 

practice standard for organic HAP rather 

than a numeric emissions limit based on 

CO as a surrogate for organic HAP. The 

EPA is denying the request for 

reconsideration on this issue. While the 

EPA disagrees that a work practice 

standard is appropriate for such HAP for 

the subcategories for which the EPA 

adopted a numeric CO limit in the final 

rule, the petitioners have not 

demonstrated that they lacked the 

opportunity to comment on this issue. 

The EPA proposed numeric CO limits 

rather than a work practice, and the 

petitioners had the opportunity to 

provide their views during the public 

comment period on the proposed rule 

regarding why it believed a work 

practice standard should instead be 


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finalized. Therefore, the EPA is denying 

the petition for reconsideration. 

Issue: Allow health based compliance 

alternatives for HCl, other acid gases 

and manganese. 

The petitioners (AMP, AF&PA, 

AHFA, AISI, ACCCI, RPU, CIBO) 

requested that the EPA adopt a HBES for 

HCl and other acid gases as well as for 

manganese, pursuant to section 

112(d)(4). The petitioners also requested 

that the EPA grant reconsideration on 

this issue to better address the 

comments and data submitted during 

the public comment period for the 

proposed rule. The EPA is denying the 

request for reconsideration of this issue. 

The EPA did not propose a HBES for 

any pollutants, but did solicit public 

comment on such standards, explaining 

its concerns regarding health-based 

standards, including the lack of 

available data on which to base such 

standards. 75 FR at 32030. The EPA 

received comments addressing those 

concerns and responded to them in the 

final rule. 76 FR at 15642. Therefore, the 

petitioners have not demonstrated that 

it lacked the opportunity to comment on 

this issue. Further, the EPA received no 

data during the public comment period 

for the proposed rule on which it could 

base a HBES for HCl, other acid gases 

or manganese. Therefore, the petitions 

do not provide substantial support to 

demonstrate that the final rule should 

be changed. For these reasons, the EPA 

is denying the petition for 

reconsideration. 

Issue: Provide additional compliance 

alternatives according to Executive 

Order 13563 (additional subcategories 

and HBES). 

The petitioner (AHFA) requested that 

the EPA provide additional compliance 

alternatives in the final rule pursuant to 

Executive Order 13563 (Improving 

Regulation and Regulatory Review), 

including HBES. The EPA is denying 

the request for reconsideration on this 

issue because it is not of central 

relevance. First, nothing in Executive 

Order 13563 affects the EPA’s discretion 

to establish HBES under the CAA. 

Additionally, the petition does not 

provide any information to address our 

concerns regarding HBES or data to 

establish such standards. 

Issue: Remove energy assessment 

requirements. 

The petitioners (AHFA, AISI, ACCCI, 

API, NPRA, AIF, CIBO, AF&PA, U.S. 

Sugar) requested that the EPA remove 

from the final rule the requirement that 

existing sources conduct an energy 

assessment. The EPA is denying the 

request for reconsideration on this issue. 

The EPA proposed an energy 

assessment requirement as a beyondthe-floor standard, and petitioners 

commented on that proposal. The EPA 

addressed those comments in the final 

rule, and petitioners have not 

demonstrated that they lacked the 

opportunity to comment on whether the 

EPA should require an energy 

assessment, including the EPA’s legal 

authority to do so. 76 FR at 15631. 

Therefore, the EPA is denying the 

petition for reconsideration. The EPA 

continues to believe that an energy 

assessment is not only authorized by the 

CAA but required as a cost-effective 

beyond-the-floor standard in accordance 

with section 112(d)(2). 

Issue: Require energy assessment to be 

conducted every 5 years. 

The petitioner (Washington Dept. of 

Ecology) requested that the EPA require 

more frequent energy assessments. The 

EPA proposed a one-time assessment 

(75 FR at p. 32036) and the petitioner 

has not demonstrated it lacked the 

opportunity to comment on the 

frequency of the assessment 

requirement. Therefore, the EPA is 

denying the petition. 

Issue: Modify cost analysis to include 

potential fuel savings from 

implementing assessment findings. 

The petitioners (AIE, USCHPA) 

requested that the EPA modify its cost 

impacts analysis to include potential 

fuel savings from implementing energy 

assessment findings. The EPA is 

denying the petition. The impacts 

analysis, including specific mention of 

how cost savings for energy assessments 

were handled quantitatively, was 

explained in the proposal (see 75 FR 

32026), and the petitioner therefore had 

the opportunity to comment on this 

issue. For this reason, the EPA is 

denying the petition for reconsideration 

on this issue. 

Issue: Reconsider definition of ‘‘cost 

effective.’’ 

The petitioners (AIE, USCHPA) 

requested that the EPA reconsider the 

definition of ‘‘cost-effective’’ in the final 

rule. The EPA is denying the request for 

reconsideration on this issue. The EPA 

proposed to define cost-effective energy 

conservation measures as any measure 

with return of investment period of two 

years or less. 75 FR at 32036. The 

petitioners have not demonstrated it 

lacked the opportunity to comment on 

the proposed definition. Therefore, the 

EPA is denying the petition for 

reconsideration. 

Issue: Establish work practice for 

other organic HAP instead of using CO 

surrogate. 

The petitioners (AMP, JELD–WEN) 

requested that the EPA establish work 

practice standards for controlling 

organic HAP instead of using CO as a 

surrogate for organic HAP and 

establishing CO emission limits. The 

EPA is denying the request for 

reconsideration on this issue. Use of CO 

as a surrogate for organic HAP was 

subject to notice and comment. (75 FR 

32018, 75 FR 32041). Responses to 

comment on this topic were provided in 

RTC document, Volume 2, EPA–HQ– 

OAR–2002–0058–3289, see section 

‘‘Choice of Regulated Pollutants: THC 

vs. CO vs. Other Organic HAP’’. 

Issue: Provide alternative format for 

units of measure for CO emission limits 

to allow sources to use their existing 

monitoring equipment. 

The petitioners (UARG, CIBO) 

requested that the EPA provide an 

alternative format (ppm at X percent 

CO2) for units of measure for CO 

emissions in addition to ppm at 3 

percent oxygen. The EPA is denying the 

petition because the petitioners do not 

demonstrate that it was impracticable to 

comment on this issue. The format for 

units of measure for the limits was 

provided in the proposed rule, and 

petitioners could have commented on 

whether the proposed units were 

appropriate. 

Issue: New source emission limits are 

unachievable and the EPA should 

collect additional fuel variability data 

from top performing units to adjust the 

limits. 

The petitioner (AF&PA) requested 

that the EPA adjust the emissions limits 

for new sources by collecting additional 

data from the best performing units that 

they believed would result in increased 

variability. The petitioners have not 

demonstrated that they lacked the 

opportunity to comment. We proposed 

standards based on the data we had, 

including data collected during the ICR 

process in which petitioners 

participated, and that data were 

available for public review. Therefore, 

petitioners could have commented on 

this issue. Second, the CAA requires 

that we base the standards on the 

sources for which we have emissions 

information. Petitioners are always free 

to provide more information to us and 

the EPA specifically requested new data 

at each stage of the rulemaking to 

support the development of emission 

limits for each subcategory. (75 FR 

32041, 76 FR 28663, 76 FR 80612). The 

EPA has incorporated revised data 

corrections or new data submittals in its 

analysis for the final rule. The EPA is 

denying the request for reconsideration. 

Issue: Adjust the methodology for 

computing MACT floors to address 

statistical errors and variability 

concerns. 

The petitioners (AISI, ACCCI, AF&PA) 

requested that the EPA adjust the 


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methodology for computing MACT 

floors to address statistical errors and 

variability concerns, including: (1) 

Dataset reflects the ‘‘best of the best’’ 

units; (2) misapplication of statistical 

formulae to address distribution, 

confidence limits, and variability; and 

(3) failure to address variability in 

emissions from one unit over time. The 

methods used to compute the MACT 

floors were subject to notice and 

comment. Where new data or data 

corrections have been submitted that 

might alter data distributions, 

identifying best performers or 

application of fuel variability factors, 

these changes have been made in the 

final rule, but the general methodology 

remains the same. See Solite Corp. v. 

EPA, 952 F.2d 473, 485 (D.C. Cir. 1991) 

(public had sufficient notice of final rule 

threshold calculations where 

methodology did not change 

significantly from proposed rule). The 

EPA explained the MACT floor 

methodology in the proposed rule, and 

addressed comments received on the 

proposed methodology in the final rule 

(75 FR 32019–26, 32027–29, 76 15621– 

30, 76 FR 80614). Therefore, the EPA is 

denying the request for reconsideration. 

Issue: Modify the basis for ranking the 

top performing units. 

The petitioner (WEPCO) requested 

that the EPA modify the basis for 

ranking the top performing units, 

especially for new units, according to 

the average performance of the unit. The 

EPA is denying the petition. The 

methods used to rank units to establish 

the MACT floors were subject to notice 

and comment. The EPA explained its 

methodology in the proposed rule and 

addressed comments received on the 

ranking of data for computing the 

MACT floor in the final rule (75 FR 

32019–26, 32027–29, 76 FR 15627). 

Issue: Do not use a pollutant-bypollutant approach to establish MACT 

floors. 

The petitioners (AISI, ACCCI, AF&PA) 

requested that the EPA not use a 

pollutant-by-pollutant approach to 

establish MACT floors. The petitioners 

stated that this method is not a 

reasonable interpretation of Section 

112(d)(3) of the CAA and that MACT 

floors should reflect levels achieved in 

practice, not aspirational controls. The 

EPA is denying the petition for 

reconsideration on this issue because it 

does not demonstrate that it was 

impracticable to comment on the issue. 

The EPA proposed MACT floors based 

on the pollutant-by-pollutant 

methodology, and therefore petitioners 

could, and in fact did, provide 

comments opposing this approach. See 

75 FR 32021, 32029. The EPA addressed 

comments received on this approach in 

the final rule (76 FR 15621–23). 

Therefore, the EPA is denying the 

petition. 

Issue: Revise approach to establish 

MACT floors where there is non-detect 

data. 

The petitioner (Sierra Club) requested 

that the EPA not use the approach it 

used in the final rule based on the 

representative detection level (RDL) to 

establish MACT floors because it does 

not reflect actual emissions of any 

source within the subcategory. Further, 

the petitioner questioned the basis of 

the selected detection level, and 

whether or not other variability 

adjustments (e.g., UPL analysis) 

sufficiently account for measurement 

imprecision. The EPA is denying the 

petition. The three times representative 

detection level approach was subject to 

notice and comment. The EPA 

explained its rationale for this approach 

in the proposed rule (75 FR 32021) and 

responded to comments received in the 

final rule (76 FR 15623, 76 FR 80611). 

Issue: The approach used to set 

MACT floor limits for dioxin/furan 

emissions is flawed and the EPA should 

establish an isomer-specific approach. 

The petitioner (WEPCO) requested 

that the EPA establish an isomerspecific approach for dioxin/furan 

emissions because the three times 

detection level approach for dioxin/ 

furan emissions is flawed. The EPA is 

denying the petition. This approach was 

subject to notice and comment. 

Rationale and responses to comments 

on this approach were provided at (75 

FR 32021, 32041, 76 FR 15623). Further, 

the methods for establishing a 

representative detection level for 

dioxin/furan have been revised to 

account for the sensitivity of individual 

isomers, see rationale provided at (76 

FR 80606). 

Issue: Incorporate a fuel variability 

factor for PM based on the ash content 

of the fuel used by best performing 

units. 

The petitioners (WEPCO, CIBO) 

requested that the EPA incorporate a 

fuel variability factor for PM based on 

the ash content of the fuel used by best 

performing units. The MACT floor 

methodology was explained in the June 

4, 2010 proposal which included fuel 

variability factors that did not reflect the 

ash content of the fuel. Therefore, the 

petitioner could have commented 

recommending that the EPA do so, and, 

in fact, comments were provided on this 

issue. The EPA is denying the petition 

for reconsideration on this issue because 

it does not demonstrate that it was 

impracticable to comment on the issue. 

Responses to comment on this topic 

were provided in RTC document, 

Volume 1, EPA–HQ–OAR–2002–0058– 

3289, see section ‘‘MACT Floor 

Methodology: Fuel Analysis 

Variability’’. 

Issue: Allow energy assessors to 

determine the time needed to conduct 

assessment. 

The petitioner (Washington Dept. of 

Ecology) requested that the EPA allow 

the energy assessor to determine the 

time needed to conduct the energy 

assessment. The EPA is denying the 

petition. The duration of energy 

assessments was subject to notice and 

comment and the duration remains up 

to the affected source. Specific concerns 

with maximum duration requirements 

included in the March 21, 2011 final 

rule were clarified in the December 23, 

2011 proposed notice of 

reconsideration. (76 FR 80615) 

Issue: The unit designed to burn gas 

1 subcategory should allow for limited 

use of liquid fuels. 

The petitioners (ACC, CEG, API, 

NPRA) requested that the EPA allow 

units in the Gas 1 subcategory for 

limited use of liquid fuels; for example, 

units with a federally enforceable 

permit on back up fuels or units burning 

10 percent or less of its heat input from 

liquid fuels should qualify as gas 1 

units. The EPA is denying the petition 

because it does not demonstrate that it 

was impracticable to comment on the 

issue. The EPA proposed definitions of 

the various subcategories, and 

petitioners had the opportunity to 

comment on those definitions, 

including the proposed definition of the 

Gas 1 subcategory which did allow for 

the limited use of liquid fuels. The EPA 

addressed comments received on this 

issue in the final rule (76 FR 15620). 

Issue: The unit designed to burn gas 

1 subcategory should automatically 

include other gaseous fuels such as 

petrochemical process gas and landfill 

gas. 

The petitioners (ACC, AIF, WM) 

requested that the EPA redefine the unit 

designed to burn gas 1 subcategory to 

automatically include other gaseous 

fuels such as petrochemical process gas 

and LFG, especially when the LFG is 

routed to a treatment system prior to use 

or sale. The EPA proposed definitions of 

units designed to burn gas 1 and units 

designed to burn gas 2 (other), and 

therefore the petitioner had the 

opportunity to comment on these 

definitions and to recommend that other 

gases be included in the definition of 

the Gas 1 subcategory (75 FR 32017, 

32065). The EPA addressed comments 

received on this issue in the final rule 

(76 FR 15638). Therefore, the EPA is 

denying the petition. 


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Issue: Reconsider the emission 

standards established for the unit 

designed to burn gas 2 subcategory. 

Petitioners (AIF, CIBO, WM, CEG) 

requested that the EPA reconsider the 

emission standards for the unit designed 

to burn gas 2 subcategory in light of 

what they feel was a limited dataset and 

lack of data from a diverse set of fuel 

types. The EPA is denying the petition. 

The MACT floor methodology was open 

to notice and comment in the June 4, 

2010 proposal. The EPA proposed 

emissions standards for this subcategory 

and the petitioners had an opportunity 

to comment on the proposed standards 

and the data on which the standards 

were based. The EPA further notes that 

the CAA requires that the MACT 

standards be based on the best 

performing sources for which the 

Administrator has emissions 

information. 

Issue: Adjust the ‘‘metal process 

furnaces’’ subcategory definition to 

include any gas-fired process furnace. 

The petitioners (AISI, ACCCI) 

requested that the EPA adjust the ‘‘metal 

process furnaces’’ subcategory 

definition to include any gas-fired 

process furnace. The EPA is denying the 

petition. The definition of the 

subcategory for metal process furnaces 

was subject to notice and comment. (75 

FR 32064, 76 FR 15620). 

Issue: The designed to burn rationale 

for subcategorization is arbitrary. 

The petitioner (Sierra Club) alleged 

that the designed to burn rationale for 

subcategorization is arbitrary, especially 

considering the large number of co-fired 

units in the inventory. The EPA 

proposed subcategories based on boiler 

design, and the petitioner has not 

demonstrated that it was impracticable 

to comment on the issue. In fact, the 

petitioner did submit comments on the 

proposed rule opposing the EPA’s 

proposed subcategorization approach. 

Therefore, the EPA is denying the 

petition. 

Issue: The EPA should consider 

exempting units from NSR. 

The petitioners (MSU, PSU, Purdue, 

Citizens Thermal Energy) requested that 

the EPA consider exempting units from 

NSR who switch fuels, install pollution 

controls, or construct energy efficiency 

projects to meet the requirements of this 

rule because complying with the rule 

requirements will trigger NSR. The EPA 

is denying the petition. The 

applicability of NSR is outside the scope 

of this rulemaking. Moreover, it was not 

impracticable to comment on this issue 

during the 2011 rulemaking, in fact, 

comments were submitted on this issue, 

to which the EPA responded. See RTC 

document, Volume 2, EPA–HQ–OAR– 

2002–0058–3289, DCN EPA–HQ–OAR– 

2002–0058–2729.1, excerpt 17. 

Issue: Remove the 10 percent penalty 

for sources opting to use the emission 

averaging compliance alternative. 

The petitioners (AMP, MSU, PSU, 

Purdue, RPU, U.S. Sugar, Citizens 

Thermal Energy) requested that the EPA 

remove the 10 percent penalty for 

sources opting to use the emission 

averaging compliance alternative. The 

EPA is denying the petition. The EPA 

proposed an emissions averaging 

approach that included the 10 percent 

adjustment factor. (75 FR 32035) 

Therefore, the petition does not 

demonstrate that it was impracticable to 

comment on this issue. Responses to 

comment on this topic were provided in 

RTC document, Volume 2, EPA–HQ– 

OAR–2002–0058–3289, see section 

‘‘Emissions Averaging.’’ 

Issue: Allow emissions averaging 

across subcategories. 

The petitioners (MSU, PSU, Purdue, 

RPU, Citizens Thermal Energy) 

requested that the EPA allow emissions 

averaging across subcategories. The EPA 

is denying the petition. The EPA 

proposed an emissions averaging 

approach that did not allow averaging 

across subcategories, and petitioners 

therefore had the opportunity to 

comment recommending that the EPA 

allow such averaging. Responses to 

comment on this topic were provided in 

RTC document, Volume 2, EPA–HQ– 

OAR–2002–0058–3289, DCN EPA–HQ– 

OAR–2002–0058–3213.1, excerpt 175. 

Issue: Allow a source’s actual heat 

input instead of the maximum design 

heat input to be used in the emissions 

averaging provisions. 

The petitioner (CIBO) requested that 

the EPA allow a source’s actual heat 

input instead of the maximum design 

heat input to be used in the emissions 

averaging provisions of the final rule. 

The EPA proposed an emissions 

averaging approach that was based on 

the maximum rated heat input capacity, 

and petitioners therefore had the 

opportunity to comment recommending 

that the EPA base the averaging on 

actual heat input. Therefore, the EPA is 

denying the petition. 

Issue: Reduce stack testing frequency 

to once every five years to reduce 

burden on facilities. 

The petitioners (ACC, CIBO, JELD– 

WEN) requested that the EPA reduce 

stack testing frequency to once every 5 

years and rely on the extensive set of 

continuous parameter monitoring in 

order to reduce burden on facilities. The 

EPA is denying the petition. The EPA 

proposed to require stack testing every 

year. The petition does not demonstrate 

that it was impracticable to comment on 

this issue, and the petitioners could 

have submitted comments requesting 

less frequent stack testing. 

Issue: Incorporate detailed fuel 

sampling procedures using 

incorporation by reference mechanisms 

instead of detailing sampling 

procedures in the regulatory language. 

The petitioner (CIBO) requested that 

the EPA incorporate detailed fuel 

sampling procedures using 

incorporation by reference mechanisms 

and citing credible literature (e.g., 

American Society for Testing and 

Materials) instead of detailing sampling 

procedures in the regulatory language 

since sampling procedures are subject to 

change over time. The EPA is denying 

the petition because the petitioner has 

not demonstrated that it was 

impracticable to comment on this issue. 

The EPA proposed fuel sampling 

procedures in the regulatory text in the 

June 4, 2010 proposal, and the 

petitioner therefore had the opportunity 

to comment recommending its preferred 

approach. 

Issue: Remove the advanced submittal 

requirement for site-specific fuel 

monitoring plans before each analysis. 

The petitioner (UARG) requested that 

the EPA remove the advanced submittal 

requirement for site-specific fuel 

monitoring plans before each analysis, 

especially if monthly frequency is 

maintained. If the fuel monitoring plan 

requirement remains, the petitioner 

requests that the EPA remove the 

requirement to report things that might 

change, such as unanticipated fuel use 

(based on unanticipated fuel changes). 

The EPA is denying the petition and 

disagrees with the commenter. First, the 

EPA proposed a fuel monitoring plan, 

and petitioners had the opportunity to 

comment on the plan requirement. The 

final rule requires submittal of a fuel 

monitoring plan 60 days before 

demonstrating initial compliance. The 

rule does not require re-submittal of this 

plan before each monthly analysis, see 

40 CFR section 63.7521(b)(1). 

Issue: Allow EPA Method 5B to 

demonstrate compliance with PM 

emission limits. 

The petitioner (UARG) requested that 

the EPA allow EPA Method 5B to 

demonstrate compliance with PM 

emission limits. The EPA is denying the 

petition because it does not demonstrate 

that it was impracticable to comment on 

this issue. The EPA proposed methods 

to demonstrate compliance in the June 

4, 2010 proposal and did not propose to 

allow Method 5B for PM compliance 

demonstrations. Therefore, the 

petitioner had the opportunity to submit 

comments recommending that the EPA 

allow the use of this method. For this 


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reason, the EPA is denying the petition 

on this issue. 

Issue: Remove or make references to 

Methods 2, 2F, 2G and 4 optional. 

The petitioner (UARG) requested that 

the EPA remove or make references to 

EPA Methods 2, 2F, 2G and 4 optional. 

The EPA is denying the petition because 

it does not demonstrate that it was 

impracticable to comment on this issue. 

The EPA proposed methods to 

demonstrate compliance in the June 4, 

2010 proposal and did not propose to 

make EPA Methods 2, 2F, 2G and 4 

optional. Therefore, the petitioner had 

the opportunity to submit comments 

recommending that the EPA make the 

use of these methods optional. For this 

reason, the EPA is denying the petition 

on this issue. 

Issue: Allow sources to petition for 

alternative PM monitoring requirements 

based on source-specific limitations. 

The petitioner (CEG) requested that 

the EPA allow sources to petition for 

alternative PM monitoring requirements 

based on source-specific limitations 

(e.g., common stacks with more than 

one subcategory). The EPA is denying 

this petition because it is not of central 

relevance to this rulemaking. The 

General Provisions at 40 CFR 63.8 allow 

sources to petition the EPA for 

alternative monitoring plans. Therefore, 

no such provision is needed in this final 

rule. 

Issue: Allow sources with overlapping 

CEMS regulations to comply with 

existing QA/QC plans or 40 CFR part 75 

Appendices A and B. 

The petitioners (CIBO, CMI) requested 

that the EPA allow sources with 

overlapping CEMS regulations to 

comply with existing QA/QC plans or 

40 CFR part 75 Appendices A and B. 

The EPA is denying this petition 

because it is not of central relevance to 

this rulemaking. 

Issue: No justification or discussion 

was provided on why the EPA selected 

12 hours as the averaging time period 

and also why the EPA selected block 

averages instead of rolling averages. 

The petitioner (Sierra Club) alleges 

that the EPA provided no justification or 

discussion explaining why the EPA 

selected 12 hours as the averaging time 

period and why the EPA selected block 

averages instead of rolling averages for 

parameter monitor. The petitioner 

requested that the EPA clarify that the 

averaging times for continuous 

parameter monitoring should be the 

same as the averaging times during the 

most recent performance test. Averaging 

times were open to notice and comment 

in the June 4, 2010 proposal. In the June 

2010 proposal, we required that 

parameters be set based on 4-hour block 

averages during the compliance test, 

and that continuous compliance be 

demonstrated by monitoring 12-hour 

block average values for most 

parameters. We selected this averaging 

period to reflect operating conditions 

during the performance test to ensure 

the control system is continuously 

operating at the same or better level as 

during a performance test demonstrating 

compliance with the emission limits. 

Therefore, the EPA is denying the 

petition. 

Issue: The EPA position regarding 

treatment of ‘‘out-of-control’’ and 

‘‘maintenance’’ periods as deviations is 

not supported or explained. 

The petitioner (UARG) alleges that the 

EPA position regarding treatment of 

‘‘out-of-control’’ and ‘‘maintenance’’ 

periods as deviations is not supported 

or explained. The petitioner requested 

that the EPA revise the definition of 

‘‘deviation’’ to be consistent with how 

deviation is treated with respect to CO 

CEMS and CPMS. The EPA is denying 

the petition. The definition of 

deviations was open to notice and 

comment in the June 4, 2010 proposal. 

Issue: Require checks of pressure 

monitoring taps only if reading is 

abnormal. 

The petitioner (CMI) requested that 

the EPA require checks of pressure 

monitoring taps only if reading is 

abnormal. The requirement to check 

pressure tap pluggage daily was open to 

notice and comment in the June 2010 

proposal. In addition, the EPA is 

denying this petition because it is not of 

central relevance to this rulemaking. 

Issue: The EPA has not sufficiently 

correlated emission limits to operating 

parameters and should not set 

enforceable limits on maximum and 

minimum control device operating 

parameters. 

The petitioners (UARG, AMP, CIBO) 

alleges that the EPA has not sufficiently 

correlated emission limits to operating 

parameters and requested the EPA not 

to set enforceable limits on maximum 

and minimum control device operating 

parameters. One petitioner (CIBO) 

requested that the rule should allow 

sources to set their own ESP secondary 

voltage requirement based on load and 

coal quality since power consumption 

by an ESP is influenced by factors other 

than operating load, including ESP 

design, amount of PM collected, and 

resistivity of the PM. Other petitioners 

(UARG and AMP) also indicate that the 

limits set on control devices inhibit the 

flexibility to operate control devices 

with a margin of safety. The EPA is 

denying the petition. Operating limits 

were open to notice and comment in the 

June 4, 2010 proposal. 

Issue: The EPA should delay 

incorporating PS 17 in this rule until the 

revisions for PS 17 are completed. 

The petitioner (UARG) requested that 

the EPA delay incorporating PS 17 in 

this rule, which outlines how to select 

and install CPMS, until the revisions for 

PS 17 are completed. 

The EPA is denying this petition. The 

final rule did not incorporate PS 17, or 

any other PS, in the provision regarding 

selection and installation of CPMS and 

ongoing quality assurance of data from 

CPMS. Comments related to revising PS 

17 are outside the scope of this 

rulemaking. (RTC document, Chapter 

11, EPA–HQ–OAR–2002–0058–3289, 

DCN EPA–HQ–OAR–2002–0058– 

2960.1, excerpt 150). 

Issue: The EPA should not set an 

enforceable operating limit on opacity. 

The petitioner (UARG) alleged that 

there is insufficient correlation between 

opacity and PM emissions and 

requested that the EPA not set an 

enforceable operating limit on opacity. 

The EPA is denying the petition. The 

EPA proposed opacity limits in the June 

4, 2010 proposal and the petitioner 

therefore had the opportunity to 

comment on the proposed limits, 

including comments requesting that no 

limit be established. 

Issue: Update outdated BLDS 

Guidance. 

The petitioner (UARG) requested that 

the EPA update the outdated BLDS 

Guidance that is currently incorporated 

by reference. The EPA is denying this 

petition. The current guidance 

document is the most recent guidance 

available and comments related to 

revising the guidance document are 

outside the scope of this rulemaking. 

(RTC document, Chapter 11, EPA–HQ– 

OAR–2002–0058–3289, DCN EPA–HQ– 

OAR–2002–0058–2997.1, excerpt 10). 

Issue: The EPA should reconsider 

emission limits for HCl on coal-fired 

boilers using a hot-side ESP for 

particulate control. 

The petitioners (MSU, PSU, Purdue, 

Citizens Thermal Energy) requested that 

the EPA reconsider emission limits for 

HCl on coal-fired boilers using a hotside ESP for particulate control. The 

petitioners are unaware of any HCl 

control devices that are compatible with 

a hot-side ESP. The EPA is denying the 

petition. The basis for subcategorization 

was subject to notice and comment. The 

EPA did not propose a separate 

subcategory for such units, and the 

petitioner could have commented 

recommending that the agency do so. 

(75 FR 32012, 76 FR 15617–18, 76 FR 

80607) Further, the EPA disagrees with 

the petitioner that the subcategories 


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could be based on the level of controls 

installed on the unit. 

Issue: The EPA should change 

electronic reporting requirements to 

avoid WebFIRE and ERT shortcomings. 

The petitioner (UARG) requested that 

the EPA change the electronic reporting 

requirements to avoid WebFIRE and 

ERT shortcomings. The petitioner 

requested that to meet the EPA’s 

obligations under the Paperwork 

Reduction Act the EPA specify each 

individual data item requested in the 

ERT. The petitioner also requests that 

the EPA explain how the ERT electronic 

signature mechanisms will meet the 

requirements of the Cross-Media 

Electronic Reporting Rule. 

The EPA is denying the petition 

because it does not demonstrate that it 

was impracticable to comment on this 

issue. The EPA proposed to require the 

use of the ERT and WebFIRE, and the 

petitioner therefore had the opportunity 

to comment on any concerns with the 

proposed approach. 

Issue: Eliminate gas curtailment 

notification requirements or adjust the 

frequency of these notifications to be 

consistent with the reporting 

requirements in the Title V program. 

The petitioner (AIF) requested that 

the EPA eliminate the gas curtailment 

notification requirements or adjust the 

frequency of these notifications to be 

consistent with the semi-annual 

reporting requirements in the Title V 

program. The EPA is denying the 

petition. Reporting requirements were 

open to notice and comment in the June 

4, 2010 proposal. 

Issue: Allow facilities to become area 

or synthetic minor sources instead of 

installing controls. 

The petitioner (GPSP) requested that 

the EPA allow facilities to become area 

or synthetic minor sources instead of 

installing controls. The EPA is denying 

the petition. Whether or not sources 

elect to become area or synthetic minor 

sources is not of central relevance to 

this rulemaking, as nothing in this rule 

affects whether or how a source can 

become a synthetic minor source (RTC 

document, EPA–HQ–OAR–2002–0058– 

3289, Volume 1, DCN EPA–HQ–OAR– 

2002–0058–3176.2, excerpt 4). 

VI. Impacts of This Final Rule 

A. What are the incremental air 

impacts? 

Table 4 of this preamble illustrates, 

for each basic fuel subcategory, the total 

emissions reductions achieved by the 

final amended rule (i.e., the difference 

in emissions between a boiler or process 

heater controlled to the amended floor 

level of control and boilers or process 

heaters at the current baseline) for new 

and existing sources. Nationwide 

emissions of selected HAP (i.e., HCl, 

HF, mercury, metals, and VOC) will be 

reduced by 44,300 tpy. This is an 

incremental increase of 4,000 tpy in 

HAP reductions compared to the 

estimates in the March 2011 final rule. 

This increase is due mainly to changes 

in the inventory (336 units were added 

since the March 2011 inventory). 

Excluding the changes in the inventory, 

the amendments to the regulatory 

provisions themselves resulted in a 

decrease of 1,100 tpy of estimated 

reductions, part of this incremental 

reduction in HAP is contributed to edits 

to the baseline emission data received 

since the March 2011 final rule, as well 

as changes to the subcategories and 

emission limits as a result of this 

amended rule. The amendments to the 

final rule are expected to result in an 

additional 4,600 tpy of reductions in 

HCl emissions. The amendments are 

also expected to have a modest effect on 

mercury, estimated to range from a 

slight decrease of 0.12 tpy up to a slight 

increase of 0.96 tpy in emission 

reductions as a result of the changes to 

the regulatory requirements. Reductions 

in emissions of filterable PM will 

decrease by 18,500 tpy due to the final 

amended rule. Reductions in emissions 

of non-mercury metals (i.e., antimony, 

arsenic, beryllium, cadmium, 

chromium, cobalt, lead, manganese, 

nickel, and selenium) will decrease by 

260 tpy. In addition, the amendments 

are estimated to result in an additional 

50,100 tpy of reductions in SO2

emissions. A discussion of the 

methodology used to estimate 

emissions, emissions reductions, and 

incremental emission reductions is 

presented in ‘‘Revised (August 2012) 

Methodology for Estimating Cost and 

Emission Impacts for Industrial, 

Commercial, and Institutional Boilers 

and Process Heaters NESHAP—Major 

Source’’ in the docket. 

TABLE 4—SUMMARY OF TOTAL EMISSIONS REDUCTIONS FOR THE FINAL AMENDED RULE

[tons/yr] 

Source Subcategory HCl PM 

Non 

mercury 

metals a

Mercury b VOC 

Existing Units ....................................... Limited Use .......................................... 1 2 0.42 2.1E–04 ....... 0.48 

Solid units ............................................ 36,737 21,367 147 0.4 to 1.5 ..... 1,619 

Liquid units ........................................... 2,143 9,434 2,315 0.9 to 1 ........ 620 

Non-Continental Liquid units ............... 35 3 1 0.01 to 0.02 23 

Gas 1 (NG/RG) units ........................... 20 117 0.3 0.01 ............. 88 

Gas 1 Metallurgical Furnaces .............. 0.4 3 0.02 0.001 ........... 27 

Gas 2 (other) units ............................... 4 8 0.06 3.8E–03 to 

4.6E–03.

40 

New Units ............................................ Solid units ............................................ 0 351 5 0.02 ............. 0 

Liquid units ........................................... 0 0 0 0 .................. 0 

Gas 1 units .......................................... 0 0 0 0 .................. 0 

Gas 1 Metallurgical Furnaces .............. 0 0 0 0 .................. 0 

Gas 2 (other) units ............................... 0 0 0 0 .................. 0 

a Includes antimony, arsenic, beryllium, cadmium, chromium, cobalt, lead, manganese, nickel, and selenium. 

b Mercury reductions are presented as a range due to adjustments on reported fractions and limits of detection. See memorandum entitled 

‘‘Revised (March 2012) Methodology for Estimating Cost and Emissions Impacts for Industrial, Commercial, Institutional Boilers and Process 

Heaters National Emission Standards for Hazardous Air Pollutants—Major Source’’ for a description of the two methods for estimating mercury 

reductions. 


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B. What are the incremental water and 

solid waste impacts? 

The EPA estimated the additional 

water usage that would result from 

installing wet scrubbers to meet the 

amended emission limits for HCl would 

be 556 million gallons per year for 

existing sources compared to the current 

baseline. In addition to the increased 

water usage, an additional 160 million 

gallons per year of wastewater would be 

produced for existing sources. Only half 

of these incremental changes are due to 

changes in the regulatory provisions. 

The other half is due to changes in the 

number of identified existing units and 

projected new units. The annual costs of 

treating the additional wastewater are 

$1.2 million. These additional costs are 

accounted for in the incremental control 

cost estimates. 

The EPA estimated the additional 

solid waste that would result due to the 

amendments to be 138,000 tpy, with 

nearly all due to changes in the 

regulatory provisions. Solid waste is 

generated from flyash and dust captured 

in PM and mercury controls as well as 

from spent carbon that is injected into 

exhaust streams or used to filter gas 

streams. The costs of handling the 

additional solid waste generated are 

$5.8 million. These costs are also 

accounted for in the incremental control 

costs estimates. 

A discussion of the methodology used 

to estimate incremental impacts is 

presented in ‘‘Revised (August 2012) 

Methodology for Estimating Cost and 

Emission Impacts for Industrial, 

Commercial, and Institutional Boilers 

and Process Heaters NESHAP—Major 

Source’’ in the docket. 

C. What are the incremental energy 

impacts? 

The EPA estimated that the March 

2011 final rule would result in an 

increase of about 1.4 billion kWh/yr in 

national energy usage from the 

electricity required to operate control 

devices, such as wet scrubbers, 

electrostatic precipitators and fabric 

filters which are expected to be installed 

to meet the final rule. The amendments 

are expected to decrease energy usage 

by a net 143 million kWh/yr compared 

to the March 2011 rule. These 

reductions are driven by the regulatory 

provisions of these amendments. 

Additionally, the EPA expects these 

amendments will result in a decrease of 

4.4 million MMBtu/yr in fuel savings, 

compared with the estimates in the 

March 2011 final rule. 

D. What are the incremental cost 

impacts? 

For these final amendments, we 

estimated the incremental difference 

between the national costs impacts for 

the final amended rule and the March 

2011 final rule. First, we determined the 

control measures, work practices, and 

monitoring and testing requirements 

that would be required by boilers and 

process heaters located at major source 

facilities to comply with the final 

amended rule. To estimate the national 

cost impacts of the final amended rule 

for existing sources, we used the 

identical methodology used to estimate 

the cost impacts for the March 2011 

final rule with one exception. In this 

revised analysis, it was assumed that 

several liquid fuel units that reported 

natural gas firing capability would 

switch to natural gas as a compliance 

option instead of installing add-on 

controls to demonstrate compliance 

with the emission limits. Thus, the only 

costs to these units would be the tuneup work practice costs. A discussion of 

the methodology used to estimate cost 

impacts is presented in ‘‘Revised 

(August 2012) Methodology for 

Estimating Cost and Emission Impacts 

for Industrial, Commercial, and 

Institutional Boilers and Process Heaters 

NESHAP—Major Source’’ in the docket. 

The resulting total national cost 

impact of the final amended rule is $4.7 

billion in capital expenditures and $1.5 

billion per year in total annual costs, 

considering fuel savings. The total 

capital expenditures are slightly lower 

than estimated for the March 2011 final 

rule, but the total annual costs are 

slightly higher than estimated for the 

March 2011 final rule. See 76 FR 15651. 

The total capital and annual costs 

include costs for control devices, work 

practices, testing and monitoring. 

In order to determine the incremental 

cost impacts of the amended 

requirements and emission limits, we 

first estimated the cost impacts of the 

additional existing boilers and process 

heaters added to the Boiler MACT 

inventory database since promulgation 

of the March 2011 final rule and the 

revised number of new boilers and 

process heaters that could be potentially 

constructed. Since the March 2011 final 

rule, we became aware of 72 major 

source facilities that were not 

previously in the Boiler MACT 

inventory database. Adding the boilers 

and process heaters located at these 

newly identified major source facilities 

resulted in 73 additional coal-fired 

units, 32 additional biomass-fired units, 

82 additional oil-fired units, and 149 

additional gas-fired units. Our revised 

number of new boilers and process 

heaters included 82 additional biomass 

units, 1,728 additional gas 1 units and 

13 fewer liquid units. 

The resulting cost impact for these 

additional existing and new boilers and 

process heaters is $1.0 billion in capital 

expenditures and $0.31 billion per year 

in total annual costs, considering fuel 

savings. 

Therefore, discounting the added 

costs for the additional boilers and 

process heaters included in the costs 

analysis, the estimated incremental cost 

impacts for these amended requirements 

on existing and new boilers and process 

heaters are $1.0 billion in capital 

expenditures and $0.13 billion per year 

in total annual costs less than the costs 

estimated in the March 2011 rule. 

Table 5 of this preamble shows the 

total capital and annual cost impacts of 

the final amended rule for each 

subcategory. Costs include testing and 

monitoring costs, but not recordkeeping 

and reporting costs. 

TABLE 5—SUMMARY OF TOTAL CAPITAL AND ANNUAL COSTS FOR NEW AND EXISTING SOURCES FOR THE FINAL AMENDED

RULE

Source Subcategory 

Estimated/ 

projected 

number of 

affected units 

Capital costs 

(106 $) 

Testing and 

monitoring 

annualized 

costs 

(106 $/yr) 

Annualized cost 

(106 $/yr) 

(considering 

fuel savings) 

Existing Units ................................... Coal units ......................................... 621 .............. 2,554 46 904 

Biomass units .................................. 502 .............. 405 29 109 

Heavy Liquid units ........................... 319 .............. 761 5 .4 221 

Light Liquid units .............................. 615 .............. 712 4 .2 166 

Non-Continental Liquid units ........... 21 ................ 62 0 .8 17 

Gas 1 (NG/RG) units ....................... 11,929 ......... 77 0 .9 (295 ) 


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TABLE 5—SUMMARY OF TOTAL CAPITAL AND ANNUAL COSTS FOR NEW AND EXISTING SOURCES FOR THE FINAL AMENDED

RULE—Continued 

Source Subcategory 

Estimated/ 

projected 

number of 

affected units 

Capital costs 

(106 $) 

Testing and 

monitoring 

annualized 

costs 

(106 $/yr) 

Annualized cost 

(106 $/yr) 

(considering 

fuel savings) 

Gas 2 (other) units ........................... 129 .............. 138 2 .3 58 

Energy Assessment ......................... ALL ................................................... 1,700 (Facilities).N/A N/A 28 

New Units ........................................ Coal units ......................................... 0 .................. 0 0 0 

Biomass units .................................. 82 ................ 381 5 .6 a 99 

Liquid units ....................................... 0 .................. 0 0 0 

Gas 1 (NG/RG) units ....................... 1,762 ........... 11 0 a 5.1 

Gas 2 (other) units ........................... 0 .................. 0 0 0 

aTotal annualized costs for new units do not account for fuel savings since no fuel savings are estimated in the first year for new units. 

Potential control device cost savings 

and increased recordkeeping and 

reporting costs associated with the 

emissions averaging provisions in the 

final rule are not accounted for in either 

the capital or annualized cost estimates. 

A discussion of the methodology used 

to estimate cost impacts is presented in 

‘‘Revised (August 2012) Methodology 

for Estimating Cost and Emission 

Impacts for Industrial, Commercial, and 

Institutional Boilers and Process Heaters 

NESHAP—Major Source’’ in the docket. 

E. What are the economic impacts? 

The EPA analyzed the economic 

impacts of this final amended rule using 

the methodology that was discussed in 

the March 2011 final rule RIA and in the 

preamble to the March 2011 final rule. 

See FR 76 15651. The market impact 

results are very similar to the results 

presented in the March 2011 final rule 

and the RIA. The agency’s economic 

model suggests the average national 

price increases for industrial sectors are 

less than 0.01 percent, while average 

annual domestic production may fall by 

less than 0.01 percent. 

Because of higher domestic prices, 

imports slightly rise. The results for 

sales tests for small businesses were 

somewhat reduced than those 

calculated for the March 2011 final rule. 

For the sales tests using small 

companies identified in the Combustion 

Survey, the mean cost to receipts 

dropped from 4 percent in the RIA to 3 

percent for this final amended rule and 

the median was 0.2 percent for the RIA 

and also 0.2 percent for this final 

amended rule. The number of parent 

companies with sales tests exceeding 3 

percent dropped from 8 in the RIA to 5 

for this final amended rule. There was 

no change in the results for small public 

entities. Median cost is still about $1.1 

million and representative small major 

public entities would have cost-torevenue ratios above 10 percent. The 

change in employment estimates 

between the RIA and the final amended 

rule is minimal. In the RIA for the 

March 2011 final rule, we estimated 

employment changes ranging between 

¥3,100 to +6,500 employees, with a 

central estimate of +1,700. For this final 

amended rule we estimate employment 

changes ranging between ¥2,600 to 

+5,400 employees, with a central 

estimate of +1,400. These estimated 

annual employment changes compared 

to the baseline employment, and are for 

the time period for which the 

annualized cost applies (2015 to 2029). 

F. What are the benefits of this final 

rule? 

We calculated health benefits using 

the methodology described in the RIA 

prepared for the March 21, 2011 final 

rule. We incorporated the revised 

emission reductions estimated for this 

reconsideration final rule into the 

analysis. We were unable to estimate the 

benefits from reducing exposure to HAP 

and ozone, ecosystem impairment and 

visibility impairment, including 

reducing 180,000 tons of carbon 

monoxide, 39,000 tons of HCl, 500 tons 

of HF, 2,500 tons of other metals and 

3,100 to 5,300 pounds of mercury. 

Please refer to the full description of the 

unquantified benefits as well as 

technical details of the analysis and its 

limitations and uncertainties in the final 

Boiler RIA (March 2011). These 

monetized benefits are approximately 

23 percent higher than the March 2011 

final rule benefits due to the increase in 

SO2 emission reductions associated 

with the additional units affected by the 

rule and the revised HCl limit. We 

estimate the total monetized benefits of 

this final regulatory action to be $27 

billion to $67 billion at a 3 percent 

discount rate and $25 to $61 billion at 

a 7 percent discount rate. All estimates 

are for the implementation year (2015) 

in 2008$. A summary of the monetized 

benefits estimates at discount rates of 3 

percent and 7 percent is provided in 

Table 6 of this preamble. A summary of 

the avoided health incidences is 

provided in Table 7 of this preamble. 

TABLE 6—SUMMARY OF THE MONETIZED BENEFITS ESTIMATES FOR THE FINAL BOILER MACT 

[millions of 2008$] a b

Pollutant 

Emissions 

reductions 

(tons) 

Total monetized benefits 

(at 3% discount rate) 

Total monetized benefits 

(at 7% discount rate) 

PM2.5-related benefits 

Direct PM2.5 ............................ 14,139 $1,200 to $2,900 ................................................ $1,100 to $ $2,700 

SO2 ........................................ 572,000 $26,000 to $64,000 ............................................ $24,000 to $61,000 


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TABLE 6—SUMMARY OF THE MONETIZED BENEFITS ESTIMATES FOR THE FINAL BOILER MACT—Continued 

[millions of 2008$] a b

Pollutant 

Emissions 

reductions 

(tons) 

Total monetized benefits 

(at 3% discount rate) 

Total monetized benefits 

(at 7% discount rate) 

Total ................................ $27,000 to $67,000 ............................................ $25,000 to $61,000. 

aAll estimates are for the implementation year (2015), and are rounded to two significant figures so numbers may not sum across rows. All 

fine particles are assumed to have equivalent health effects because the scientific evidence is not yet sufficient to allow differentiation of effect 

estimates by particle type. Benefits from reducing hazardous air pollutants (HAP) are not included. These estimates do not include energy 

disbenefits valued at $24 million (using a 3 percent discount rate). These benefits reflect existing boilers and new boilers anticipated to come online by 2015. bThere are some slight differences in the emission reductions used in the RIA and those used in the air impacts section of this preamble due 

to some late changes in the data that were received after the RIA was completed. Refer to the memoranda ‘‘Revised (August 2012) Methodology 

for Estimating Cost and Emission Impacts for Industrial, Commercial, and Institutional Boilers and Process Heaters NESHAP—Major Source’’ for 

a discussion of the differences. 

TABLE 7—SUMMARY OF THE AVOIDED

HEALTH INCIDENCES FOR THE FINAL

BOILER MACT a

Avoided health 

incidences 

Premature Mortality .............. 3,000–7,900 

Morbidity ............................... ........................

Chronic Bronchitis ................ 2,000 

Acute Myocardial Infarction .. 5,000 

Hospital Admissions, Respiratory .............................. 750 

Hospital Admissions, Cardiovascular ............................. 1,600 

Emergency Room Visits, 

Respiratory ........................ 3,000 

Acute Bronchitis .................... 4,600 

Work Loss Days ................... 390,000 

Asthma Exacerbation ........... 51,000 

Minor Restricted Activity 

Days .................................. 2,300,000 

Lower Respiratory Symptoms .................................. 55,000 

Upper Respiratory Symptoms .................................. 41,000 

aAll estimates are for the implementation 

year (2015), and are rounded to two significant figures. All fine particles are assumed to 

have equivalent health effects because the 

scientific evidence is not yet sufficient to allow 

differentiation of effect estimates by particle 

type. Benefits from reducing HAP are not included. These benefits reflect existing boilers 

and new boilers anticipated to come online by 

2015. 

G. What are the incremental secondary 

air impacts? 

For units adding controls to meet the 

amended emission limits, we anticipate 

very minor secondary air impacts. The 

combustion of fuel needed to generate 

additional electricity would yield slight 

increases in emissions, including NOX, 

CO, PM and SO2 and an increase in CO2

emissions. Since NOX and SO2 are 

covered by capped emissions trading 

programs and methodological 

limitations prevent us from quantifying 

the change in CO and PM, we do not 

estimate an increase in secondary air 

impacts for this final rule from 

additional electricity demand. We do 

estimate greenhouse gas impacts, which 

result from increased electricity 

consumption, to be 859,200 tpy from 

existing units and 79,700 tpy from new 

units. This is 19,200 tpy less than the 

estimated greenhouse gas impacts 

associated with the March 2011 final 

rule. 

VII. Statutory and Executive Order 

Reviews 

A. Executive Order 12866: Regulatory 

Planning and Review and Executive 

Order 13563: Improving Regulation and 

Regulatory Review 

Under section 3(f)(1) of Executive 

Order 12866 (58 FR 51735, October 4, 

1993), this action is an ‘‘economically 

significant regulatory action’’ because it 

is likely to have an annual effect on the 

economy of $100 million or more or 

adversely affect in a material way the 

economy, a sector of the economy, 

productivity, competition, jobs, the 

environment, public health or safety, or 

state, local, or tribal governments or 

communities. Accordingly, the EPA 

submitted this action to the OMB for 

review under Executive Orders 12866 

and 13563 (76 FR 3821, January 21, 

2011) and any changes made in 

response to the OMB recommendations 

have been documented in the docket for 

this action. 

The EPA did prepare a new RIA for 

this action. The EPA prepared an 

assessment of the changes in the costs 

and benefits of this final rule compared 

to the costs and benefits associated with 

the March 21, 2011, final rule. Overall, 

the costs and impacts are estimated to 

be similar to the costs and impacts 

associated with the previous final rule, 

although the distribution is somewhat 

different and the number of affected 

units in the inventory has increased by 

about 302 units. When comparing the 

costs using only those sources that were 

part of the final rule inventory, the costs 

have decreased. The EPA re-ran the 

multimarket model to assess changes in 

economic impacts, and this analysis 

confirmed that the overall economic 

impacts are similar to the previous final 

rule. The benefits are projected to 

increase by about 20 percent because of 

the increase in the estimated SO2

reductions. A summary of the costs and 

benefits of the previous final rule is 

provided in the preamble to the 

previous final rule (see 76 FR 15658) 

and the detailed analysis for the 

previous final rule is provided in the 

RIA for the previous final rule. In 

addition, memoranda are provided in 

the docket to document the changes in 

costs, economic impacts, and benefits 

associated with this final rule, shown in 

Table 8. 

TABLE 8—SUMMARY OF THE MONETIZED BENEFITS, SOCIAL COSTS AND NET BENEFITS FOR THE FINAL BOILER MACT 

RECONSIDERATION IN 2015 

[Millions of 2008$] 1

 3 percent discount rate 7 percent discount rate 

Total Monetized Benefits 2 ................................. $27,000 to $67,000 .......................................... $24,000 to $61,000. 

Total Social Costs 3 ............................................ $1,400 to $1,600 .............................................. $1,400 to $1,600. 

Net Benefits ........................................................ $26,000 to $65,000 .......................................... $23,200 to $59,000. 


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1Small entities include small businesses, small 

organizations, and small governmental 

jurisdictions. For purposes of assessing the impacts 

of today’s rule on small entities, small entity is 

defined as: (1) A small business according to Small 

Business Administration (SBA) size standards by 

the North American Industry Classification System 

category of the owning entity. The range of small 

business size standards for the affected industries 

ranges from 500 to 1,000 employees, except for 

petroleum refining and electric utilities. In these 

latter two industries, the size standard is 1,500 

employees and a mass throughput of 75,000 barrels/ 

day or less, and 4 million kilowatt-hours of 

production or less, respectively; (2) a small 

governmental jurisdiction that is a government of a 

city, county, town, school district or special district 

with a population of less than 50,000; and (3) a 

small organization that is any not-for-profit 

enterprise which is independently owned and 

operated and is not dominant in its field. 

TABLE 8—SUMMARY OF THE MONETIZED BENEFITS, SOCIAL COSTS AND NET BENEFITS FOR THE FINAL BOILER MACT 

RECONSIDERATION IN 2015—Continued 

[Millions of 2008$] 1

 3 percent discount rate 7 percent discount rate 

Non-monetized Benefits ..................................... Health effects from exposure to HAP (39,000 tons of HCl, 500 tons of HF, 3,100 to 5,300 

pounds of mercury, and 2,500 tons of other metals). 

Health effects from exposure to other criteria pollutants (180,000 tons of CO and 572,000 tons 

of SO2). 

Ecosystem effects. 

Visibility impairment. 

1All estimates are for the implementation year (2015), and are rounded to two significant figures. 

2The total monetized co-benefits reflect the human health benefits associated with reducing exposure to PM2.5 through reductions of PM2.5

precursors such as directly emitted particles, SO2, and NOX and reducing exposure to ozone through reductions of VOC. It is important to note 

that the monetized benefits include many but not all health effects associated with PM2.5 exposure. Monetized benefits are shown as a range 

from Pope et al. (2002) to Laden et al. (2006). These models assume that all fine particles, regardless of their chemical composition, are equally 

potent in causing premature mortality because the scientific evidence is not yet sufficient to support the development of differential effects estimates by particle type. These estimates include the energy disbenefits valued at $24 million (using the 3 percent discount rate), which do not 

change the rounded totals. CO2-related disbenefits were calculated using the ‘‘social cost of carbon’’, which is discussed further in the RIA. 3The methodology used to estimate social costs for one year in the multimarket model using surplus changes results in the same social costs 

for both discount rates. 

B. Paperwork Reduction Act 

The OMB has approved the 

information collection requirements 

contained in the March 21, 2011 final 

rule under the provisions of the 

Paperwork Reduction Act, 44 U.S.C. 

3501 et seq. and has assigned OMB 

control number 2060–0551. The EPA 

has updated the supporting statement to 

reflect the final inventory and burden 

estimates associated with this action 

since some of the monitoring, 

recordkeeping and reporting 

requirements have changed since the 

March 21, 2011 final rule. These revised 

estimates have been sent to OMB for 

review and approval. 

The information requirements are 

based on notification, recordkeeping, 

and reporting requirements in the 

NESHAP General Provisions (40 CFR 

part 63, subpart A), which are 

mandatory for all operators subject to 

national emission standards. These 

recordkeeping and reporting 

requirements are specifically authorized 

by section 114 of the CAA (42 U.S.C. 

7414). All information submitted to the 

EPA pursuant to the recordkeeping and 

reporting requirements for which a 

claim of confidentiality is made is 

safeguarded according to agency 

policies set forth in 40 CFR part 2, 

subpart B. 

This final rule will require 

maintenance inspections of the control 

devices but will not require any 

notifications or reports beyond those 

required by the General Provisions aside 

from a notification of intent to 

commence burning solid waste 

materials and notification of alternative 

fuel use for those units that are in the 

Gas 1 subcategory but burn liquid fuels 

for periodic testing, or during periods of 

gas curtailment or gas supply 

emergencies. The recordkeeping 

requirements require only the specific 

information needed to determine 

compliance. 

The revised annual monitoring, 

reporting and recordkeeping burden for 

this collection (averaged over the first 3 

years after the effective date of the 

standards) is estimated to be $95.3 

million which is about the same as 

estimated for the March 2011 final rule. 

This includes 323,130 labor hours per 

year at a total labor cost of $30.6 million 

per year, and total non-labor capital 

costs of $64.7 million per year. This 

estimate includes initial and annual 

performance test, conducting and 

documenting an energy assessment, 

conducting fuel specifications for Gas 1 

units, repeat testing under worst-case 

conditions for solid fuel units, 

conducting and documenting a tune-up, 

semiannual excess emission reports, 

maintenance inspections, developing a 

monitoring plan, notifications and 

recordkeeping. Monitoring, testing, 

tune-up and energy assessment costs 

and cost were also included in the cost 

estimates presented in the control costs 

impacts estimates in section VI.D of this 

preamble. The total burden for the 

federal government (averaged over the 

first 3 years after the effective date of the 

standard) is estimated to be 100,608 

hours per year at a total labor cost of 

$5.3 million per year. Burden is defined 

at 5 CFR 1320.3(b). 

An agency may not conduct or 

sponsor, and a person is not required to 

respond to, a collection of information 

unless it displays a currently valid OMB 

control number. The OMB control 

numbers for the EPA’s regulations in 40 

CFR are listed in 40 CFR part 9. In 

addition, the EPA is amending the table 

in 40 CFR part 9 of currently approved 

OMB control numbers for various 

regulations to list the regulatory 

citations for the information 

requirements contained in this final 

rule. 

C. Regulatory Flexibility Act 

The RFA generally requires an agency 

to prepare a regulatory flexibility 

analysis of any rule subject to notice 

and comment rulemaking requirements 

under the Administrative Procedure Act 

or any other statute unless the agency 

certifies that the rule will not have a 

significant economic impact on a 

substantial number of small entities.1

The RFA also allows an agency to 

‘‘consider a series of closely related 

rules as one rule for the purposes of 

sections’’ 603 (initial regulatory 

flexibility analysis) and 604 (final 

regulatory flexibility analysis) in order 

to avoid ‘‘duplicative action.’’ 5 U.S.C. 

§ 605(c). This final rule is closely related 

to the final major source rule, which the 

EPA signed on February 21, 2011. The 

EPA prepared a final regulatory 

flexibility analyses in connection with 

the major source rule. Therefore, 


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pursuant to § 605(c), the EPA is not 

required to complete a final regulatory 

flexibility analysis for this rule. 

The EPA has been concerned with 

potential small entity impacts since it 

began developing the major source rule. 

The EPA conducted outreach to small 

entities and, pursuant to § 609 of RFA, 

convened a Small Business Advocacy 

Review Panel to obtain advice and 

recommendations from small entity 

representatives. 

Pursuant to the RFA, the EPA used 

the Panel’s report and prepared both an 

initial regulatory flexibility analysis and 

a final regulatory flexibility analysis in 

connection with the closely related 

major source rule. Convening an 

additional Panel and preparing an 

additional final regulatory flexibility 

analysis would be procedurally 

duplicative and is unnecessary given 

that the issues here are within the scope 

of those considered by the Panel. In 

addition, this final action would 

decrease capital and annualized costs 

on small entities by about 3 percent and 

10 percent, respectively, relative to the 

closely related final rule. 

D. Unfunded Mandates Reform Act 

Title II of the UMRA of 1995, 2 U.S.C. 

1531–1538, requires federal agencies, 

unless otherwise prohibited by law, to 

assess the effects of their regulatory 

actions on state, local and tribal 

governments and the private sector. 

Federal agencies must also develop a 

plan to provide notice to small 

governments that might be significantly 

or uniquely affected by any regulatory 

requirements. The plan must enable 

officials of affected small governments 

to have meaningful and timely input in 

the development of the EPA regulatory 

proposals with significant Federal 

intergovernmental mandates and must 

inform, educate, and advise small 

governments on compliance with the 

regulatory requirements. 

Both this rule and the March 21, 2011 

final rule contain a federal mandate that 

may result in expenditures of $100 

million or more for state, local and tribal 

governments, in the aggregate, or the 

private sector in any one year. 

Accordingly, the EPA prepared under 

section 202 of the UMRA a written 

statement for the final rule. This final 

rule also contains a federal mandate that 

may result in expenditures of $100 

million or more for state, local, and 

tribal governments, in the aggregate, or 

the private sector in any one year. The 

discussion below has been updated to 

reflect the changes. 

1. Statutory Authority 

As discussed in the March 21, 2011, 

final rule, the statutory authority for this 

final rulemaking is section 112 of the 

CAA. Title III of the CAA Amendments 

was enacted to reduce nationwide air 

toxic emissions. Section 112(b) of the 

CAA lists the 188 chemicals, 

compounds, or groups of chemicals 

deemed by Congress to be HAP. These 

toxic air pollutants are to be regulated 

by NESHAP. 

Section 112(d) of the CAA directs us 

to develop NESHAP which require 

existing and new major sources to 

control emissions of HAP using MACT 

based standards. This NESHAP applies 

to all boilers and process heaters located 

at major sources of HAP emissions. 

2. Social Costs and Benefits 

The regulatory impact analysis 

prepared for the March 21, 2011 final 

rule, which we have revised for this 

final rule, including the agency’s 

assessment of costs and benefits, is 

detailed in the ‘‘Regulatory Impact 

Analysis for the Final Industrial Boilers 

and Process Heaters MACT (2011)’’ and 

in the ‘‘Regulatory Impact Results for 

the Reconsideration Final Rule for 

National Emission Standards for 

Hazardous Air Pollutants for Industrial, 

Commercial, and Institutional Boilers 

and Process Heaters at Major Sources’’ 

in the docket. Based on estimated 

compliance costs associated with this 

final rule and the predicted change in 

prices and production in the affected 

industries, the estimated social costs of 

this rule are $1.4 to 1.6 billion (2008 

dollars). 

It is estimated that 3 years after 

implementation of this final rule, HAP 

would be reduced by 45,000 tpy, 

including reductions in HCl, hydrogen 

fluoride, metallic HAP including 

mercury, and several other organic HAP 

from boilers and process heaters. 

Studies have determined a relationship 

between exposure to these HAP and the 

onset of cancer, however, the agency is 

unable to provide a monetized estimate 

of the HAP benefits at this time. In 

addition, there are significant annual 

reductions in fine particulate matter 

(PM2.5) and in SO2 that would occur, 

including 25 thousand tons of PM2.5 and 

558 thousand tons of SO2. These 

reductions occur within 3 years after the 

implementation of the final regulation 

and are expected to continue throughout 

the life of the affected sources. The 

major health effect associated with 

reducing PM2.5 and PM2.5 precursors 

(such as SO2) are a reduction in 

premature mortality. Other health 

effects associated with PM2.5 emission 

reductions include avoiding cases of 

chronic bronchitis, heart attacks, asthma 

attacks and work-lost days (i.e., days 

when employees are unable to work). 

While we are unable to monetize the 

benefits associated with the HAP 

emissions reductions, we are able to 

monetize the benefits associated with 

the PM2.5 and SO2 emissions reductions. 

For SO2 and PM2.5, we estimated the 

benefits associated with health effects of 

PM but were unable to quantify all 

categories of benefits (particularly those 

associated with ecosystem and visibility 

effects). Our estimates of the monetized 

benefits in 2015 associated with the 

implementation of the final regulatory 

action range from $27 billion (2008 

dollars) to $67 billion (2008 dollars) 

when using a 3 percent discount rate (or 

from $25 billion (2008 dollars) to $61 

billion (2008 dollars) when using a 7 

percent discount rate). This estimate, at 

a 3 percent discount rate, is about $25 

billion (2008 dollars) to $65 billion 

(2008 dollars) higher than the estimated 

social costs shown earlier in this 

section. The general approach used to 

value benefits is discussed in more 

detail earlier in this preamble. For more 

detailed information on the benefits 

estimated for the rulemaking, refer to 

the RIA and the memos updating the 

impacts and benefits in the docket. 

3. Future and Disproportionate Costs 

The UMRA requires that we estimate, 

where accurate estimation is reasonably 

feasible, future compliance costs 

imposed by this final rule and any 

disproportionate budgetary effects. Our 

estimates of the future compliance costs 

of the rule are discussed previously in 

this preamble. 

We do not believe that there will be 

any disproportionate budgetary effects 

of this final rule on any particular areas 

of the country, state or local 

governments, types of communities 

(e.g., urban, rural) or particular industry 

segments. See the results of the 

‘‘Regulatory Impact Analysis for the 

Final Industrial Boilers and Process 

Heaters MACT (2011).’’ 

4. Effects on the National Economy 

The UMRA requires that we estimate 

the effect of this final rule on the 

national economy. To the extent 

feasible, we must estimate the effect on 

productivity, economic growth, full 

employment, creation of productive jobs 

and international competitiveness of the 

U.S. goods and services, if we determine 

that accurate estimates are reasonably 

feasible and that such effect is relevant 

and material. 

The nationwide economic impact of 

this final rule is presented in the 


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‘‘Regulatory Impact Analysis for the 

Final Industrial Boilers and Process 

Heaters MACT (2011)’’ and a 

memoranda that are included in the 

docket, entitled ‘‘Regulatory Impact 

Results for the Reconsideration Final 

Rule for National Emission Standards 

for Hazardous Air Pollutants for 

Industrial, Commercial, and 

Institutional Boilers and Process Heaters 

at Major Sources which update the RIA 

analyses. This analysis provides 

estimates of the effect of this rule on 

some of the categories mentioned above. 

The results of the economic impact 

analysis are summarized previously in 

this preamble. The results show that 

there will be a small impact on prices 

and output, and little impact on 

communities that may be affected by 

this final rule. In addition, there should 

be little impact on energy markets (in 

this case, coal, natural gas, petroleum 

products and electricity). Hence, the 

potential impacts on the categories 

mentioned above should be small. 

5. Consultation With Government 

Officials 

The UMRA requires that we describe 

the extent of the agency’s prior 

consultation with affected state, local 

and tribal officials, summarize the 

officials’ comments or concerns, and 

summarize our response to those 

comments or concerns. In addition, 

section 203 of the UMRA requires that 

we develop a plan for informing and 

advising small governments that may be 

significantly or uniquely impacted by a 

final rule. We consulted with state and 

local air pollution control officials 

during the development of the final 

rule. We have also held meetings on this 

final rule with many of the stakeholders 

from numerous individual companies, 

institutions, environmental groups, 

consultants and vendors, labor unions 

and other interested parties. We have 

added materials to the docket to 

document these meetings. 

Consistent with section 205, the EPA 

has identified and considered a 

reasonable number of regulatory 

alternatives. Additional information on 

the costs and environmental impacts of 

these regulatory alternatives is 

presented in the docket. 

The regulatory alternative upon 

which the emission limits in this final 

rule are based represents the MACT 

floors for all subcategories and, as a 

result, it is the least costly and least 

burdensome alternative. 

This rule is not subject to the 

requirements of section 203 of UMRA 

because it contains no regulatory 

requirements that might significantly or 

uniquely affect small governments. 

While some small governments may 

have some sources affected by this final 

rule, the impacts are not expected to be 

significant. Therefore, this final rule is 

not subject to the requirements of 

section 203 of the UMRA. 

E. Executive Order 13132: Federalism 

This action does not have federalism 

implications. It will not have substantial 

direct effects on the states, on the 

relationship between the national 

government and the states, or on the 

distribution of power and 

responsibilities among the various 

levels of government, as specified in 

Executive Order 13132. This final rule 

will not impose direct compliance costs 

on state or local governments, and will 

not preempt state law. Thus, Executive 

Order 13132 does not apply to this 

action. 

F. Executive Order 13175: Consultation 

and Coordination With Indian Tribal 

Governments 

This action does not have tribal 

implications, as specified in Executive 

Order 13175 (65 FR 67249, November 9, 

2000). It will not have substantial direct 

effects on tribal governments, on the 

relationship between the federal 

government and Indian tribes, or on the 

distribution of power and 

responsibilities between the federal 

government and Indian tribes, as 

specified in Executive Order 13175. 

Thus, Executive Order 13175 does not 

apply to this action. 

G. Executive Order 13045: Protection of 

Children From Environmental Health 

Risks and Safety Risks 

The EPA interprets Executive Order 

13045 (62 FR 19885, April 23, 1997) as 

applying to those regulatory actions that 

concern health or safety risks, such that 

the analysis required under section 5– 

501 of the Order has the potential to 

influence the regulation. This action is 

not subject to EO 13045 because it is 

based solely on technology 

performance. 

H. Executive Order 13211: Actions 

Concerning Regulations That 

Significantly Affect Energy Supply, 

Distribution, or Use 

This action is not a ‘‘significant 

energy action’’ as defined in Executive 

Order 13211 (66 FR 28355, May 22, 

2001), because it is not likely to have a 

significant adverse effect on the supply, 

distribution, or use of energy. For the 

March 21, 2011, final rule, we estimated 

a 0.05 percent price increase for the 

energy sector and a ¥0.02 percent 

percentage change in production. We 

estimated a 0.09 percent increase in 

energy imports. For more information 

on the estimated energy effects, please 

refer to the ‘‘Regulatory Impact Analysis 

for the Final Industrial Boilers and 

Process Heaters MACT (2011).’’ The 

analysis is available in the public 

docket. While we did not recreate the 

RIA for this final action, the energy 

impacts for existing sources decreased 

slightly, and the energy impacts for new 

source increased due to the increased 

number of new sources that is now 

projected. Overall, the projected energy 

use increased slightly but would not 

change the analysis that was conducted 

for the previous final rule. Therefore, we 

conclude that this final rule when 

implemented is not likely to have a 

significant adverse effect on the supply, 

distribution, or use of energy. 

I. National Technology Transfer and 

Advancement Act 

Section 12(d) of the NTTAA, Public 

Law 104–113, 12(d) (15 U.S.C. 272 note) 

directs the EPA to use VCS in its 

regulatory activities unless to do so 

would be inconsistent with applicable 

law or otherwise impractical. VCS are 

technical standards (e.g., materials 

specifications, test methods, sampling 

procedures, and business practices) that 

are developed or adopted by VCS 

bodies. NTTAA directs the EPA to 

provide Congress, through the OMB, 

explanations when the agency decides 

not to use available and applicable VCS. 

This action does not involve any new 

technical standards from those 

contained in the March 21, 2011 final 

rule. Therefore, the EPA did not 

consider the use of any VCS. See 76 FR 

15660–15662 for the NTTAA discussion 

in the March 21, 2011 final rule. 

J. Executive Order 12898: Federal 

Actions To Address Environmental 

Justice in Minority Populations and 

Low-Income Populations 

Executive Order 12898 (59 FR 7629, 

February 16, 1994) establishes federal 

executive policy on environmental 

justice. Its main provision directs 

federal agencies, to the greatest extent 

practicable and permitted by law, to 

make environmental justice part of their 

mission by identifying and addressing, 

as appropriate, disproportionately high 

and adverse human health or 

environmental effects of their programs, 

policies, and activities on minority 

populations and low-income 

populations in the United States. 

For the March 2011 final rule, the 

EPA determined that the rule would not 

have disproportionately high and 

adverse human health or environmental 

effects on minority or low-income 

populations because it increases the 


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level of environmental protection for all 

affected populations without having any 

disproportionately high and adverse 

human health or environmental effects 

on any population, including any 

minority or low-income population. 

Compared to the previous final rule, 

while the amendments are somewhat 

less stringent for some subcategories of 

units and more stringent for some 

others, the overall increased health 

benefits demonstrate that the 

conclusions from the environmental 

justice analysis conducted for the 

previous final rule are still valid. 

Therefore, the EPA has determined this 

final rule will not have 

disproportionately high and adverse 

human or environmental effects on 

minority or low-income populations. 

K. Congressional Review Act 

The Congressional Review Act, 5 

U.S.C. 801 et seq., as added by the Small 

Business Regulatory Enforcement 

Fairness Act of 1996, generally provides 

that before a rule may take effect, the 

agency promulgating the rule must 

submit a rule report, which includes a 

copy of the rule, to each House of the 

Congress and to the Comptroller General 

of the United States. EPA will submit a 

report containing this final rule and 

other required information to the U.S. 

Senate, the U.S. House of 

Representatives, and the Comptroller 

General of the United States prior to 

publication of the rule in the Federal 

Register. A major rule cannot take effect 

until 60 days after it is published in the 

Federal Register. This action is a ‘‘major 

rule’’ as defined by 5 U.S.C. 804(2). 

With the exception of the May 18, 2011 

(76 FR 28661), delay of the effective 

date revising subpart DDDDD at 76 FR 

15451 (March 21, 2011) being lifted 

January 31, 2013, this rule will be 

effective April 1, 2013. 

List of Subjects in 40 CFR Part 63 

Environmental protection, 

Administrative practice and procedure, 

Air pollution control, Hazardous 

substances, Incorporation by reference, 

Intergovernmental relations, Reporting 

and Recordkeeping requirements. 

Dated: December 20, 2012 

Lisa P. Jackson, 

Administrator. 

For the reasons cited in the preamble, 

title 40, chapter I, part 63 of the Code 

of Federal Regulations is amended as 

follows: 

PART 63—[AMENDED] 

■ 1. The authority for part 63 continues 

to read as follows: 

Authority: 42 U.S.C. 7401, et seq. 

■ 2. Effective January 31, 2013, the May 

18, 2011 (76 FR 28661), delay of the 

effective date revising subpart DDDDD 

at 76 FR 15451 (March 21, 2011) is 

lifted. 

Subpart A—[Amended] 

■ 3. Section 63.14 is amended by: 

■ a. Revising paragraphs (b)(19), (b)(23), 

(b)(35), (b)(40), (b)(69), and (b)(70). 

■ b. Removing and reserving paragraph 

(b)(53). 

■ c. Adding paragraphs (b)(46), (b)(55), 

and (b)(76) through (83). 

■ d. Adding paragraphs (p)(12) through 

(20). 

■ e. Adding paragraph (r). 

The revisions and additions read as 

follows: 

§ 63.14 Incorporations by reference. 

* * * * * 

(b) * * * 

(19) ASTM D95–05 (Reapproved 

2010), Standard Test Method for Water 

in Petroleum Products and Bituminous 

Materials by Distillation, approved May 

1, 2010, IBR approved for § 63.10005(i) 

and table 6 to subpart DDDDD. 

* * * * * 

(23) ASTM D4006–11, Standard Test 

Method for Water in Crude Oil by 

Distillation, including Annex A1 and 

Appendix X1, approved June 1, 2011, 

IBR approved for § 63.10005(i) and table 

6 to subpart DDDDD. 

* * * * * 

(35) ASTM D6784–02 (Reapproved 

2008) Standard Test Method for 

Elemental, Oxidized, Particle-Bound 

and Total Mercury in Flue Gas 

Generated from Coal-Fired Stationary 

Sources (Ontario Hydro Method), 

approved April 1, 2008, IBR approved 

for table 1 to subpart DDDDD of this 

part, table 2 to subpart DDDDD of this 

part, table 5 to subpart DDDDD, table 11 

to subpart DDDDD of this part, table 12 

to subpart DDDDD of this part, table 13 

to subpart DDDDD of this part, and table 

4 to subpart JJJJJJ of this part. 

* * * * * 

(40) ASTM D396–10 Standard 

Specification for Fuel Oils, approved 

October 1, 2010, IBR approved for 

§ 63.7575 and § 63.11237. 

* * * * * 

(46) ASTM D4606–03 (2007), 

Standard Test Method for Determination 

of Arsenic and Selenium in Coal by the 

Hydride Generation/Atomic Absorption 

Method, approved October 1, 2007, IBR 

approved for table 6 to subpart DDDDD. 

* * * * * 

(55) ASTM D6357–11, Test Methods 

for Determination of Trace Elements in 

Coal, Coke, and Combustion Residues 

from Coal Utilization Processes by 

Inductively Coupled Plasma Atomic 

Emission Spectrometry, approved April 

1, 2011, IBR approved for table 6 to 

subpart DDDDD. 

* * * * * 

(69) ASTM D4057–06 (Reapproved 

2011), Standard Practice for Manual 

Sampling of Petroleum and Petroleum 

Products, including Annex A1, 

approved June 1, 2011, IBR approved for 

§ 63.10005(i) and table 6 to subpart 

DDDDD. 

(70) ASTM D4177–95 (Reapproved 

2010), Standard Practice for Automatic 

Sampling of Petroleum and Petroleum 

Products, including Annexes A1 

through A6 and Appendices X1 and X2, 

approved May 1, 2010, IBR approved for 

§ 63.10005(i) and table 6 to subpart 

DDDDD. 

* * * * * 

(76) ASTM D6751–11b, Standard 

Specification for Biodiesel Fuel Blend 

Stock (B100) for Middle Distillate Fuels, 

approved July 15, 2011, IBR approved 

for § 63.7575 and § 63.11237. 

(77) ASTM D975–11b, Standard 

Specification for Diesel Fuel Oils, 

approved December 1, 2011, IBR 

approved for § 63.7575. 

(78) ASTM D5864–11 Standard Test 

Method for Determining Aerobic 

Aquatic Biodegradation of Lubricants or 

Their Components, approved March 1, 

2011, IBR approved for table 6 to 

subpart DDDDD. 

(79) ASTM D240–09 Standard Test 

Method for Heat of Combustion of 

Liquid Hydrocarbon Fuels by Bomb 

Calorimeter, approved July 1, 2009, IBR 

approved for table 6 to subpart DDDDD. 

(80) ASTM D4208–02 (2007) Standard 

Test Method for Total Chlorine in Coal 

by the Oxygen Bomb Combustion/Ion 

Selective Electrode Method, approved 

May 1, 2007, IBR approved for table 6 

to subpart DDDDD. 

(81) ASTM D5192–09 Standard 

Practice for Collection of Coal Samples 

from Core, approved June 1, 2009, IBR 

approved for table 6 to subpart DDDDD. 

(82) ASTM D7430–11ae1, Standard 

Practice for Mechanical Sampling of 

Coal, approved October 1, 2011, IBR 

approved for table 6 to subpart DDDDD. 

(83) ASTM D6883–04, Standard 

Practice for Manual Sampling of 

Stationary Coal from Railroad Cars, 

Barges, Trucks, or Stockpiles, approved 

June 1, 2004, IBR approved for table 6 

to subpart DDDDD. 

* * * * * 

(p) * * * 

(12) Method 5050 (SW–846–5050), 

Bomb Preparation Method for Solid 

Waste, Revision 0, September 1994, in 


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EPA Publication No. SW–846, Test 

Methods for Evaluating Solid Waste, 

Physical/Chemical Methods, Third 

Edition IBR approved for table 6 to 

subpart DDDDD. 

(13) Method 9056 (SW–846–9056), 

Determination of Inorganic Anions by 

Ion Chromatography, Revision 1, 

February 2007, in EPA Publication No. 

SW–846, Test Methods for Evaluating 

Solid Waste, Physical/Chemical 

Methods, Third Edition, IBR approved 

for table 6 to subpart DDDDD. 

(14) Method 9076 (SW–846–9076), 

Test Method for Total Chlorine in New 

and Used Petroleum Products by 

Oxidative Combustion and 

Microcoulometry, Revision 0, 

September 1994, in EPA Publication No. 

SW–846, Test Methods for Evaluating 

Solid Waste, Physical/Chemical 

Methods, Third Edition, IBR approved 

for table 6 to subpart DDDDD. 

(15) Method 1631 Revision E, 

Mercury in Water by Oxidation, Purge 

and Trap, and Cold Vapor Atomic 

Absorption Fluorescence Spectrometry, 

Revision E, EPA–821–R–02–019, August 

2002, IBR approved for table 6 to 

subpart DDDDD. 

(16) Method 200.8, Determination of 

Trace Elements in Waters and Wastes by 

Inductively Coupled Plasma—Mass 

Spectrometry, Revision 5.4, 1994, IBR 

approved for table 6 to subpart DDDDD. 

(17) Method 6020A (SW–846–6020A), 

Inductively Coupled Plasma-Mass 

Spectrometry, Revision 1, February 

2007, in EPA Publication No. SW–846, 

Test Methods for Evaluating Solid 

Waste, Physical/Chemical Methods, 

Third Edition, IBR approved for table 6 

to subpart DDDDD. 

(18) Method 6010C (SW–846–6010C), 

Inductively Coupled Plasma-Atomic 

Emission Spectrometry, Revision 3, 

February 2007, in EPA Publication No. 

SW–846, Test Methods for Evaluating 

Solid Waste, Physical/Chemical 

Methods, Third Edition, IBR approved 

for table 6 to subpart DDDDD. 

(19) Method 7060A (SW–846–7060A), 

Arsenic (Atomic Absorption, Furnace 

Technique), Revision 1, September 

1994, in EPA Publication No. SW–846, 

Test Methods for Evaluating Solid 

Waste, Physical/Chemical Methods, 

Third Edition, IBR approved for table 6 

to subpart DDDDD. 

(20) Method 7740 (SW–846–7740), 

Selenium (Atomic Absorption, Furnace 

Technique), Revision 0, September 

1986, in EPA Publication No. SW–846, 

Test Methods for Evaluating Solid 

Waste, Physical/Chemical Methods, 

Third Edition, IBR approved for table 6 

to subpart DDDDD. 

* * * * * 

(r) The following material is available 

for purchase from the Technical 

Association of the Pulp and Paper 

Industry (TAPPI), 15 Technology 

Parkway South, Norcross, GA 30092, 

(800) 332–8686, http://www.tappi.org. 

(1) TAPPI T 266, Determination of 

Sodium, Calcium, Copper, Iron, and 

Manganese in Pulp and Paper by 

Atomic Absorption Spectroscopy 

(Reaffirmation of T 266 om-02), Draft 

No. 2, July 2006, IBR approved for table 

6 to subpart DDDDD. 

(2) [Reserved] 

Subpart DDDDD—[Amended] 

■ 4. Section 63.7485 is revised to read 

as follows: 

§ 63.7485 Am I subject to this subpart? 

You are subject to this subpart if you 

own or operate an industrial, 

commercial, or institutional boiler or 

process heater as defined in § 63.7575 

that is located at, or is part of, a major 

source of HAP, except as specified in 

§ 63.7491. For purposes of this subpart, 

a major source of HAP is as defined in 

§ 63.2, except that for oil and natural gas 

production facilities, a major source of 

HAP is as defined in § 63.7575. 

■ 5. Section 63.7490 is amended by 

adding paragraph (e) to read as follows: 

§ 63.7490 What is the affected source of 

this subpart? 

* * * * * 

(e) An existing electric utility steam 

generating unit (EGU) that meets the 

applicability requirements of this 

subpart after the effective date of this 

final rule due to a change (e.g., fuel 

switch) is considered to be an existing 

source under this subpart. 

■ 6. Section 63.7491 is amended by: 

■ a. Revising the introductory text. 

■ b. Revising paragraph (a). 

■ c. Revising paragraph (c). 

■ d. Revising paragraph (h) 

■ e. Revising paragraph (i). 

■ f. Revising paragraph (m). 

■ g. Revising paragraph (n). 

The revisions read as follows: 

§ 63.7491 Are any boilers or process 

heaters not subject to this subpart? 

The types of boilers and process 

heaters listed in paragraphs (a) through 

(n) of this section are not subject to this 

subpart. 

(a) An electric utility steam generating 

unit (EGU) covered by subpart UUUUU 

of this part. 

* * * * * 

(c) A boiler or process heater that is 

used specifically for research and 

development, including test steam 

boilers used to provide steam for testing 

the propulsion systems on military 

vessels. This does not include units that 

provide heat or steam to a process at a 

research and development facility. 

* * * * * 

(h) Any boiler or process heater that 

is part of the affected source subject to 

another subpart of this part, such as 

boilers and process heaters used as 

control devices to comply with subparts 

JJJ, OOO, PPP, and U of this part. 

(i) Any boiler or process heater that is 

used as a control device to comply with 

another subpart of this part, or part 60, 

part 61, or part 65 of this chapter 

provided that at least 50 percent of the 

average annual heat input during any 3 

consecutive calendar years to the boiler 

or process heater is provided by 

regulated gas streams that are subject to 

another standard. 

* * * * * 

(m) A unit that burns hazardous waste 

covered by Subpart EEE of this part. A 

unit that is exempt from Subpart EEE as 

specified in § 63.1200(b) is not covered 

by Subpart EEE. 

(n) Residential boilers as defined in 

this subpart. 

* * * * * 

■ 7. Section 63.7495 is amended by: 

■ a. Revising paragraph (a). 

■ b. Revising paragraph (b). 

■ c. Adding paragraphs (e), (f), and (g). 

The revisions and additions read as 

follows: 

§ 63.7495 When do I have to comply with 

this subpart? 

(a) If you have a new or reconstructed 

boiler or process heater, you must 

comply with this subpart by January 31, 

2013, or upon startup of your boiler or 

process heater, whichever is later. 

(b) If you have an existing boiler or 

process heater, you must comply with 

this subpart no later than January 31, 

2016, except as provided in § 63.6(i). 

* * * * * 

(e) If you own or operate an 

industrial, commercial, or institutional 

boiler or process heater and would be 

subject to this subpart except for the 

exemption in § 63.7491(l) for 

commercial and industrial solid waste 

incineration units covered by part 60, 

subpart CCCC or subpart DDDD, and 

you cease combusting solid waste, you 

must be in compliance with this subpart 

and are no longer subject to part 60, 

subparts CCCC or DDDD beginning on 

the effective date of the switch as 

identified under the provisions of 

§ 60.2145(a)(2) and (3) or § 60.2710(a)(2) 

and (3). 

(f) If you own or operate an existing 

EGU that becomes subject to this 

subpart after January 31, 2013, you must 


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be in compliance with the applicable 

existing source provisions of this 

subpart on the effective date such unit 

becomes subject to this subpart. 

(g) If you own or operate an existing 

industrial, commercial, or institutional 

boiler or process heater and would be 

subject to this subpart except for a 

exemption in § 63.7491(i) that becomes 

subject to this subpart after January 31, 

2013, you must be in compliance with 

the applicable existing source 

provisions of this subpart within 3 years 

after such unit becomes subject to this 

subpart. 

■ 8.Section 63.7499 is amended by 

revising paragraphs (d) and (f) through 

(l) and adding paragraphs (p) through 

(u) to read as follows: 

§ 63.7499 What are the subcategories of 

boilers and process heaters? 

* * * * * 

(d) Stokers/sloped grate/other units 

designed to burn kiln dried biomass/ 

bio-based solid. 

* * * * * 

(f) Suspension burners designed to 

burn biomass/bio-based solid. 

(g) Fuel cells designed to burn 

biomass/bio-based solid. 

(h) Hybrid suspension/grate burners 

designed to burn wet biomass/bio-based 

solid. 

(i) Stokers/sloped grate/other units 

designed to burn wet biomass/bio-based 

solid. 

(j) Dutch ovens/pile burners designed 

to burn biomass/bio-based solid. 

(k) Units designed to burn liquid fuel 

that are non-continental units. 

(l) Units designed to burn gas 1 fuels. 

* * * * * 

(p) Units designed to burn solid fuel. 

(q) Units designed to burn liquid fuel. 

(r) Units designed to burn coal/solid 

fossil fuel. 

(s) Fluidized bed units with an 

integrated fluidized bed heat exchanger 

designed to burn coal/solid fossil fuel. 

(t) Units designed to burn heavy 

liquid fuel. 

(u) Units designed to burn light liquid 

fuel. 

■ 9. Section 63.7500 is amended by: 

■ a. Revising paragraph (a). 

■ b. Revising paragraph (c). 

■ c. Adding paragraph (d). 

■ d. Adding paragraph (e). 

■ e. Adding paragraph (f). 

§ 63.7500 What emission limitations, work 

practice standards, and operating limits 

must I meet? 

(a) You must meet the requirements in 

paragraphs (a)(1) through (3) of this 

section, except as provided in 

paragraphs (b), through (e) of this 

section. You must meet these 

requirements at all times the affected 

unit is operating, except as provided in 

paragraph (f) of this section. 

(1) You must meet each emission 

limit and work practice standard in 

Tables 1 through 3, and 11 through 13 

to this subpart that applies to your 

boiler or process heater, for each boiler 

or process heater at your source, except 

as provided under § 63.7522. The 

output-based emission limits, in units of 

pounds per million Btu of steam output, 

in Tables 1 or 2 to this subpart are an 

alternative applicable only to boilers 

and process heaters that generate steam. 

The output-based emission limits, in 

units of pounds per megawatt-hour, in 

Tables 1 or 2 to this subpart are an 

alternative applicable only to boilers 

that generate electricity. If you operate 

a new boiler or process heater, you can 

choose to comply with alternative limits 

as discussed in paragraphs (a)(1)(i) 

through (a)(1)(iii) of this section, but on 

or after January 31, 2016, you must 

comply with the emission limits in 

Table 1 to this subpart. 

(i) If your boiler or process heater 

commenced construction or 

reconstruction after June 4, 2010 and 

before May 20, 2011, you may comply 

with the emission limits in Table 1 or 

11 to this subpart until January 31, 

2016. 

(ii) If your boiler or process heater 

commenced construction or 

reconstruction after May 20, 2011 and 

before December 23, 2011, you may 

comply with the emission limits in 

Table 1 or 12 to this subpart until 

January 31, 2016. 

(iii) If your boiler or process heater 

commenced construction or 

reconstruction after December 23, 2011 

and before January 31, 2013, you may 

comply with the emission limits in 

Table 1 or 13 to this subpart until 

January 31, 2016. 

(2) You must meet each operating 

limit in Table 4 to this subpart that 

applies to your boiler or process heater. 

If you use a control device or 

combination of control devices not 

covered in Table 4 to this subpart, or 

you wish to establish and monitor an 

alternative operating limit or an 

alternative monitoring parameter, you 

must apply to the EPA Administrator for 

approval of alternative monitoring 

under § 63.8(f). 

(3) At all times, you must operate and 

maintain any affected source (as defined 

in § 63.7490), including associated air 

pollution control equipment and 

monitoring equipment, in a manner 

consistent with safety and good air 

pollution control practices for 

minimizing emissions. Determination of 

whether such operation and 

maintenance procedures are being used 

will be based on information available 

to the Administrator that may include, 

but is not limited to, monitoring results, 

review of operation and maintenance 

procedures, review of operation and 

maintenance records, and inspection of 

the source. 

* * * * * 

(c) Limited-use boilers and process 

heaters must complete a tune-up every 

5 years as specified in § 63.7540. They 

are not subject to the emission limits in 

Tables 1 and 2 or 11 through 13 to this 

subpart, the annual tune-up, or the 

energy assessment requirements in 

Table 3 to this subpart, or the operating 

limits in Table 4 to this subpart. 

(d) Boilers and process heaters with a 

heat input capacity of less than or equal 

to 5 million Btu per hour in the units 

designed to burn gas 2 (other) fuels 

subcategory or units designed to burn 

light liquid fuels subcategory must 

complete a tune-up every 5 years as 

specified in § 63.7540. 

(e) Boilers and process heaters in the 

units designed to burn gas 1 fuels 

subcategory with a heat input capacity 

of less than or equal to 5 million Btu per 

hour must complete a tune-up every 5 

years as specified in § 63.7540. Boilers 

and process heaters in the units 

designed to burn gas 1 fuels subcategory 

with a heat input capacity greater than 

5 million Btu per hour and less than 10 

million Btu per hour must complete a 

tune-up every 2 years as specified in 

§ 63.7540. Boilers and process heaters in 

the units designed to burn gas 1 fuels 

subcategory are not subject to the 

emission limits in Tables 1 and 2 or 11 

through 13 to this subpart, or the 

operating limits in Table 4 to this 

subpart. 

(f) These standards apply at all times 

the affected unit is operating, except 

during periods of startup and shutdown 

during which time you must comply 

only with Table 3 to this subpart. 

■ 10. Section 63.7501 is revised to read 

as follows: 

§ 63.7501 Affirmative Defense for Violation 

of Emission Standards During Malfunction. 

In response to an action to enforce the 

standards set forth in § 63.7500 you may 

assert an affirmative defense to a claim 

for civil penalties for violations of such 

standards that are caused by 

malfunction, as defined at § 63.2. 

Appropriate penalties may be assessed 

if you fail to meet your burden of 

proving all of the requirements in the 

affirmative defense. The affirmative 

defense shall not be available for claims 

for injunctive relief. 

(a) Assertion of affirmative defense. 

To establish the affirmative defense in 


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any action to enforce such a standard, 

you must timely meet the reporting 

requirements in paragraph (b) of this 

section, and must prove by a 

preponderance of evidence that: 

(1) The violation: 

(i) Was caused by a sudden, 

infrequent, and unavoidable failure of 

air pollution control equipment, process 

equipment, or a process to operate in a 

normal or usual manner; and 

(ii) Could not have been prevented 

through careful planning, proper design, 

or better operation and maintenance 

practices; and 

(iii) Did not stem from any activity or 

event that could have been foreseen and 

avoided, or planned for; and 

(iv) Was not part of a recurring pattern 

indicative of inadequate design, 

operation, or maintenance; and 

(2) Repairs were made as 

expeditiously as possible when a 

violation occurred; and 

(3) The frequency, amount, and 

duration of the violation (including any 

bypass) were minimized to the 

maximum extent practicable; and 

(4) If the violation resulted from a 

bypass of control equipment or a 

process, then the bypass was 

unavoidable to prevent loss of life, 

personal injury, or severe property 

damage; and 

(5) All possible steps were taken to 

minimize the impact of the violation on 

ambient air quality, the environment, 

and human health; and 

(6) All emissions monitoring and 

control systems were kept in operation 

if at all possible, consistent with safety 

and good air pollution control practices; 

and 

(7) All of the actions in response to 

the violation were documented by 

properly signed, contemporaneous 

operating logs; and 

(8) At all times, the affected source 

was operated in a manner consistent 

with good practices for minimizing 

emissions; and 

(9) A written root cause analysis has 

been prepared, the purpose of which is 

to determine, correct, and eliminate the 

primary causes of the malfunction and 

the violation resulting from the 

malfunction event at issue. The analysis 

shall also specify, using best monitoring 

methods and engineering judgment, the 

amount of any emissions that were the 

result of the malfunction. 

(b) Report. The owner or operator 

seeking to assert an affirmative defense 

shall submit a written report to the 

Administrator with all necessary 

supporting documentation, that it has 

met the requirements set forth in 

§ 63.7500 of this section. This 

affirmative defense report shall be 

included in the first periodic 

compliance, deviation report or excess 

emission report otherwise required after 

the initial occurrence of the violation of 

the relevant standard (which may be the 

end of any applicable averaging period). 

If such compliance, deviation report or 

excess emission report is due less than 

45 days after the initial occurrence of 

the violation, the affirmative defense 

report may be included in the second 

compliance, deviation report or excess 

emission report due after the initial 

occurrence of the violation of the 

relevant standard. 

■ 11. Section 63.7505 is amended by: 

■ a. Revising paragraph (a). 

■ b. Revising paragraph (c). 

■ c. Revising paragraphs (d) 

introductory text, (d)(1) introductory 

text, and (d)(1)(iii). 

§ 63.7505 What are my general 

requirements for complying with this 

subpart? 

(a) You must be in compliance with 

the emission limits, work practice 

standards, and operating limits in this 

subpart. These limits apply to you at all 

times the affected unit is operating 

except for the periods noted in 

§ 63.7500(f). 

* * * * * 

(c) You must demonstrate compliance 

with all applicable emission limits 

using performance stack testing, fuel 

analysis, or continuous monitoring 

systems (CMS), including a continuous 

emission monitoring system (CEMS), 

continuous opacity monitoring system 

(COMS), continuous parameter 

monitoring system (CPMS), or 

particulate matter continuous parameter 

monitoring system (PM CPMS), where 

applicable. You may demonstrate 

compliance with the applicable 

emission limit for hydrogen chloride 

(HCl), mercury, or total selected metals 

(TSM) using fuel analysis if the 

emission rate calculated according to 

§ 63.7530(c) is less than the applicable 

emission limit. (For gaseous fuels, you 

may not use fuel analyses to comply 

with the TSM alternative standard or 

the HCl standard.) Otherwise, you must 

demonstrate compliance for HCl, 

mercury, or TSM using performance 

testing, if subject to an applicable 

emission limit listed in Tables 1, 2, or 

11 through 13 to this subpart. 

(d) If you demonstrate compliance 

with any applicable emission limit 

through performance testing and 

subsequent compliance with operating 

limits (including the use of CPMS), or 

with a CEMS, or COMS, you must 

develop a site-specific monitoring plan 

according to the requirements in 

paragraphs (d)(1) through (4) of this 

section for the use of any CEMS, COMS, 

or CPMS. This requirement also applies 

to you if you petition the EPA 

Administrator for alternative monitoring 

parameters under § 63.8(f). 

(1) For each CMS required in this 

section (including CEMS, COMS, or 

CPMS), you must develop, and submit 

to the Administrator for approval upon 

request, a site-specific monitoring plan 

that addresses design, data collection, 

and the quality assurance and quality 

control elements outlined in § 63.8(d) 

and the elements described in 

paragraphs (d)(1)(i) through (iii) of this 

section. You must submit this sitespecific monitoring plan, if requested, at 

least 60 days before your initial 

performance evaluation of your CMS. 

This requirement to develop and submit 

a site specific monitoring plan does not 

apply to affected sources with existing 

CEMS or COMS operated according to 

the performance specifications under 

appendix B to part 60 of this chapter 

and that meet the requirements of 

§ 63.7525. Using the process described 

in § 63.8(f)(4), you may request approval 

of alternative monitoring system quality 

assurance and quality control 

procedures in place of those specified in 

this paragraph and, if approved, include 

the alternatives in your site-specific 

monitoring plan. 

* * * * * 

(iii) Performance evaluation 

procedures and acceptance criteria (e.g., 

calibrations, accuracy audits, analytical 

drift). 

* * * * * 

■ 12. Section 63.7510 is revised to read 

as follows: 

§ 63.7510 What are my initial compliance 

requirements and by what date must I 

conduct them? 

(a) For each boiler or process heater 

that is required or that you elect to 

demonstrate compliance with any of the 

applicable emission limits in Tables 1 or 

2 or 11 through 13 of this subpart 

through performance testing, your 

initial compliance requirements include 

all the following: 

(1) Conduct performance tests 

according to § 63.7520 and Table 5 to 

this subpart. 

(2) Conduct a fuel analysis for each 

type of fuel burned in your boiler or 

process heater according to § 63.7521 

and Table 6 to this subpart, except as 

specified in paragraphs (a)(2)(i) through 

(iii) of this section. 

(i) For each boiler or process heater 

that burns a single type of fuel, you are 

not required to conduct a fuel analysis 

for each type of fuel burned in your 

boiler or process heater according to 


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§ 63.7521 and Table 6 to this subpart. 

For purposes of this subpart, units that 

use a supplemental fuel only for startup, 

unit shutdown, and transient flame 

stability purposes still qualify as units 

that burn a single type of fuel, and the 

supplemental fuel is not subject to the 

fuel analysis requirements under 

§ 63.7521 and Table 6 to this subpart. 

(ii) When natural gas, refinery gas, or 

other gas 1 fuels are co-fired with other 

fuels, you are not required to conduct a 

fuel analysis of those fuels according to 

§ 63.7521 and Table 6 to this subpart. If 

gaseous fuels other than natural gas, 

refinery gas, or other gas 1 fuels are cofired with other fuels and those gaseous 

fuels are subject to another subpart of 

this part, part 60, part 61, or part 65, you 

are not required to conduct a fuel 

analysis of those fuels according to 

§ 63.7521 and Table 6 to this subpart. 

(iii) You are not required to conduct 

a chlorine fuel analysis for any gaseous 

fuels. You must conduct a fuel analysis 

for mercury on gaseous fuels unless the 

fuel is exempted in paragraphs (a)(2)(i) 

and (ii) of this section. 

(3) Establish operating limits 

according to § 63.7530 and Table 7 to 

this subpart. 

(4) Conduct CMS performance 

evaluations according to § 63.7525. 

(b) For each boiler or process heater 

that you elect to demonstrate 

compliance with the applicable 

emission limits in Tables 1 or 2 or 11 

through 13 to this subpart for HCl, 

mercury, or TSM through fuel analysis, 

your initial compliance requirement is 

to conduct a fuel analysis for each type 

of fuel burned in your boiler or process 

heater according to § 63.7521 and Table 

6 to this subpart and establish operating 

limits according to § 63.7530 and Table 

8 to this subpart. The fuels described in 

paragraph (a)(2)(i) and (ii) of this section 

are exempt from these fuel analysis and 

operating limit requirements. The fuels 

described in paragraph (a)(2)(ii) of this 

section are exempt from the chloride 

fuel analysis and operating limit 

requirements. Boilers and process 

heaters that use a CEMS for mercury or 

HCl are exempt from the performance 

testing and operating limit requirements 

specified in paragraph (a) of this section 

for the HAP for which CEMS are used. 

(c) If your boiler or process heater is 

subject to a carbon monoxide (CO) limit, 

your initial compliance demonstration 

for CO is to conduct a performance test 

for CO according to Table 5 to this 

subpart or conduct a performance 

evaluation of your continuous CO 

monitor, if applicable, according to 

§ 63.7525(a). Boilers and process heaters 

that use a CO CEMS to comply with the 

applicable alternative CO CEMS 

emission standard listed in Tables 12, or 

11 through 13 to this subpart, as 

specified in § 63.7525(a), are exempt 

from the initial CO performance testing 

and oxygen concentration operating 

limit requirements specified in 

paragraph (a) of this section. 

(d) If your boiler or process heater is 

subject to a PM limit, your initial 

compliance demonstration for PM is to 

conduct a performance test in 

accordance with § 63.7520 and Table 5 

to this subpart. 

(e) For existing affected sources (as 

defined in § 63.7490), you must 

complete the initial compliance 

demonstration, as specified in 

paragraphs (a) through (d) of this 

section, no later than 180 days after the 

compliance date that is specified for 

your source in § 63.7495 and according 

to the applicable provisions in 

§ 63.7(a)(2) as cited in Table 10 to this 

subpart, except as specified in 

paragraph (j) of this section. You must 

complete an initial tune-up by following 

the procedures described in 

§ 63.7540(a)(10)(i) through (vi) no later 

than the compliance date specified in 

§ 63.7495, except as specified in 

paragraph (j) of this section. You must 

complete the one-time energy 

assessment specified in Table 3 to this 

subpart no later than the compliance 

date specified in § 63.7495, except as 

specified in paragraph (j) of this section. 

(f) For new or reconstructed affected 

sources (as defined in § 63.7490), you 

must complete the initial compliance 

demonstration with the emission limits 

no later than July 30, 2013 or within 180 

days after startup of the source, 

whichever is later. If you are 

demonstrating compliance with an 

emission limit in Tables 11 through 13 

to this subpart that is less stringent (that 

is, higher) than the applicable emission 

limit in Table 1 to this subpart, you 

must demonstrate compliance with the 

applicable emission limit in Table 1 no 

later than July 29, 2016. 

(g) For new or reconstructed affected 

sources (as defined in § 63.7490), you 

must demonstrate initial compliance 

with the applicable work practice 

standards in Table 3 to this subpart 

within the applicable annual, biennial, 

or 5-year schedule as specified in 

§ 63.7540(a) following the initial 

compliance date specified in 

§ 63.7495(a). Thereafter, you are 

required to complete the applicable 

annual, biennial, or 5-year tune-up as 

specified in § 63.7540(a). 

(h) For affected sources (as defined in 

§ 63.7490) that ceased burning solid 

waste consistent with § 63.7495(e) and 

for which the initial compliance date 

has passed, you must demonstrate 

compliance within 60 days of the 

effective date of the waste-to-fuel 

switch. If you have not conducted your 

compliance demonstration for this 

subpart within the previous 12 months, 

you must complete all compliance 

demonstrations for this subpart before 

you commence or recommence 

combustion of solid waste. 

(i) For an existing EGU that becomes 

subject after January 31, 2013, you must 

demonstrate compliance within 180 

days after becoming an affected source. 

(j) For existing affected sources (as 

defined in § 63.7490) that have not 

operated between the effective date of 

the rule and the compliance date that is 

specified for your source in § 63.7495, 

you must complete the initial 

compliance demonstration, if subject to 

the emission limits in Table 2 to this 

subpart, as specified in paragraphs (a) 

through (d) of this section, no later than 

180 days after the re-start of the affected 

source and according to the applicable 

provisions in § 63.7(a)(2) as cited in 

Table 10 to this subpart. You must 

complete an initial tune-up by following 

the procedures described in 

§ 63.7540(a)(10)(i) through (vi) no later 

than 30 days after the re-start of the 

affected source and, if applicable, 

complete the one-time energy 

assessment specified in Table 3 to this 

subpart, no later than the compliance 

date specified in § 63.7495. 

■ 13. Section 63.7515 is revised to read 

as follows: 

§ 63.7515 When must I conduct 

subsequent performance tests, fuel 

analyses, or tune-ups? 

(a) You must conduct all applicable 

performance tests according to § 63.7520 

on an annual basis, except as specified 

in paragraphs (b) through (e), (g), and (h) 

of this section. Annual performance 

tests must be completed no more than 

13 months after the previous 

performance test, except as specified in 

paragraphs (b) through (e), (g), and (h) 

of this section. 

(b) If your performance tests for a 

given pollutant for at least 2 consecutive 

years show that your emissions are at or 

below 75 percent of the emission limit 

(or, in limited instances as specified in 

Tables 1 and 2 or 11 through 13 to this 

subpart, at or below the emission limit) 

for the pollutant, and if there are no 

changes in the operation of the 

individual boiler or process heater or air 

pollution control equipment that could 

increase emissions, you may choose to 

conduct performance tests for the 

pollutant every third year. Each such 

performance test must be conducted no 

more than 37 months after the previous 

performance test. If you elect to 


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7166 Federal Register / Vol. 78, No. 21 / Thursday, January 31, 2013 / Rules and Regulations 

demonstrate compliance using emission 

averaging under § 63.7522, you must 

continue to conduct performance tests 

annually. The requirement to test at 

maximum chloride input level is 

waived unless the stack test is 

conducted for HCl. The requirement to 

test at maximum mercury input level is 

waived unless the stack test is 

conducted for mercury. The 

requirement to test at maximum TSM 

input level is waived unless the stack 

test is conducted for TSM. 

(c) If a performance test shows 

emissions exceeded the emission limit 

or 75 percent of the emission limit (as 

specified in Tables 1 and 2 or 11 

through 13 to this subpart) for a 

pollutant, you must conduct annual 

performance tests for that pollutant 

until all performance tests over a 

consecutive 2-year period meet the 

required level (at or below 75 percent of 

the emission limit, as specified in 

Tables 1 and 2 or 11 through 13 to this 

subpart). 

(d) If you are required to meet an 

applicable tune-up work practice 

standard, you must conduct an annual, 

biennial, or 5-year performance tune-up 

according to § 63.7540(a)(10), (11), or 

(12), respectively. Each annual tune-up 

specified in § 63.7540(a)(10) must be no 

more than 13 months after the previous 

tune-up. Each biennial tune-up 

specified in § 63.7540(a)(11) must be 

conducted no more than 25 months after 

the previous tune-up. Each 5-year tuneup specified in § 63.7540(a)(12) must be 

conducted no more than 61 months after 

the previous tune-up. For a new or 

reconstructed affected source (as 

defined in § 63.7490), the first annual, 

biennial, or 5-year tune-up must be no 

later than 13 months, 25 months, or 61 

months, respectively, after the initial 

startup of the new or reconstructed 

affected source. 

(e) If you demonstrate compliance 

with the mercury, HCl, or TSM based on 

fuel analysis, you must conduct a 

monthly fuel analysis according to 

§ 63.7521 for each type of fuel burned 

that is subject to an emission limit in 

Tables 1, 2, or 11 through 13 to this 

subpart. You may comply with this 

monthly requirement by completing the 

fuel analysis any time within the 

calendar month as long as the analysis 

is separated from the previous analysis 

by at least 14 calendar days. If you burn 

a new type of fuel, you must conduct a 

fuel analysis before burning the new 

type of fuel in your boiler or process 

heater. You must still meet all 

applicable continuous compliance 

requirements in § 63.7540. If each of 12 

consecutive monthly fuel analyses 

demonstrates 75 percent or less of the 

compliance level, you may decrease the 

fuel analysis frequency to quarterly for 

that fuel. If any quarterly sample 

exceeds 75 percent of the compliance 

level or you begin burning a new type 

of fuel, you must return to monthly 

monitoring for that fuel, until 12 months 

of fuel analyses are again less than 75 

percent of the compliance level. 

(f) You must report the results of 

performance tests and the associated 

fuel analyses within 60 days after the 

completion of the performance tests. 

This report must also verify that the 

operating limits for each boiler or 

process heater have not changed or 

provide documentation of revised 

operating limits established according to 

§ 63.7530 and Table 7 to this subpart, as 

applicable. The reports for all 

subsequent performance tests must 

include all applicable information 

required in § 63.7550. 

(g) For affected sources (as defined in 

§ 63.7490) that have not operated since 

the previous compliance demonstration 

and more than one year has passed 

since the previous compliance 

demonstration, you must complete the 

subsequent compliance demonstration, 

if subject to the emission limits in 

Tables 1, 2, or 11 through 13 to this 

subpart, no later than 180 days after the 

re-start of the affected source and 

according to the applicable provisions 

in § 63.7(a)(2) as cited in Table 10 to this 

subpart. You must complete a 

subsequent tune-up by following the 

procedures described in 

§ 63.7540(a)(10)(i) through (vi) and the 

schedule described in § 63.7540(a)(13) 

for units that are not operating at the 

time of their scheduled tune-up. 

(h) If your affected boiler or process 

heater is in the unit designed to burn 

light liquid subcategory and you 

combust ultra low sulfur liquid fuel, 

you do not need to conduct further 

performance tests if the pollutants 

measured during the initial compliance 

performance tests meet the emission 

limits in Tables 1 or 2 of this subpart 

providing you demonstrate ongoing 

compliance with the emissions limits by 

monitoring and recording the type of 

fuel combusted on a monthly basis. If 

you intend to use a fuel other than ultra 

low sulfur liquid fuel, natural gas, 

refinery gas, or other gas 1 fuel, you 

must conduct new performance tests 

within 60 days of burning the new fuel 

type. 

(i) If you operate a CO CEMS that 

meets the Performance Specifications 

outlined in § 63.7525(a)(3) of this 

subpart to demonstrate compliance with 

the applicable alternative CO CEMS 

emission standard listed in Tables 1, 2, 

or 11 through 13 to this subpart, you are 

not required to conduct CO performance 

tests and are not subject to the oxygen 

concentration operating limit 

requirement specified in § 63.7510(a). 

■ 14. Section § 63.7520 is amended by 

revising paragraphs (a), (c), (d), and (e) 

and adding paragraph (f) to read as 

follows: 

§ 63.7520 What stack tests and procedures 

must I use? 

(a) You must conduct all performance 

tests according to § 63.7(c), (d), (f), and 

(h). You must also develop a sitespecific stack test plan according to the 

requirements in § 63.7(c). You shall 

conduct all performance tests under 

such conditions as the Administrator 

specifies to you based on the 

representative performance of each 

boiler or process heater for the period 

being tested. Upon request, you shall 

make available to the Administrator 

such records as may be necessary to 

determine the conditions of the 

performance tests. 

* * * * * 

(c) You must conduct each 

performance test under the specific 

conditions listed in Tables 5 and 7 to 

this subpart. You must conduct 

performance tests at representative 

operating load conditions while burning 

the type of fuel or mixture of fuels that 

has the highest content of chlorine and 

mercury, and TSM if you are opting to 

comply with the TSM alternative 

standard and you must demonstrate 

initial compliance and establish your 

operating limits based on these 

performance tests. These requirements 

could result in the need to conduct 

more than one performance test. 

Following each performance test and 

until the next performance test, you 

must comply with the operating limit 

for operating load conditions specified 

in Table 4 to this subpart. 

(d) You must conduct a minimum of 

three separate test runs for each 

performance test required in this 

section, as specified in § 63.7(e)(3). Each 

test run must comply with the 

minimum applicable sampling times or 

volumes specified in Tables 1 and 2 or 

11 through 13 to this subpart. 

(e) To determine compliance with the 

emission limits, you must use the FFactor methodology and equations in 

sections 12.2 and 12.3 of EPA Method 

19 at 40 CFR part 60, appendix A–7 of 

this chapter to convert the measured 

particulate matter (PM) concentrations, 

the measured HCl concentrations, the 

measured mercury concentrations, and 

the measured TSM concentrations that 

result from the performance test to 

pounds per million Btu heat input 

emission rates. 


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Federal Register / Vol. 78, No. 21 / Thursday, January 31, 2013 / Rules and Regulations 7167 

(f) Except for a 30-day rolling average 

based on CEMS (or sorbent trap 

monitoring system) data, if 

measurement results for any pollutant 

are reported as below the method 

detection level (e.g., laboratory 

analytical results for one or more 

sample components are below the 

method defined analytical detection 

level), you must use the method 

detection level as the measured 

emissions level for that pollutant in 

calculating compliance. The measured 

result for a multiple component analysis 

(e.g., analytical values for multiple 

Method 29 fractions both for individual 

HAP metals and for total HAP metals) 

may include a combination of method 

detection level data and analytical data 

reported above the method detection 

level. 

■ 15. Section 63.7521 is revised to read 

as follows: 

§ 63.7521 What fuel analyses, fuel 

specification, and procedures must I use? 

(a) For solid and liquid fuels, you 

must conduct fuel analyses for chloride 

and mercury according to the 

procedures in paragraphs (b) through (e) 

of this section and Table 6 to this 

subpart, as applicable. For solid fuels 

and liquid fuels, you must also conduct 

fuel analyses for TSM if you are opting 

to comply with the TSM alternative 

standard. For gas 2 (other) fuels, you 

must conduct fuel analyses for mercury 

according to the procedures in 

paragraphs (b) through (e) of this section 

and Table 6 to this subpart, as 

applicable. (For gaseous fuels, you may 

not use fuel analyses to comply with the 

TSM alternative standard or the HCl 

standard.) For purposes of complying 

with this section, a fuel gas system that 

consists of multiple gaseous fuels 

collected and mixed with each other is 

considered a single fuel type and 

sampling and analysis is only required 

on the combined fuel gas system that 

will feed the boiler or process heater. 

Sampling and analysis of the individual 

gaseous streams prior to combining is 

not required. You are not required to 

conduct fuel analyses for fuels used for 

only startup, unit shutdown, and 

transient flame stability purposes. You 

are required to conduct fuel analyses 

only for fuels and units that are subject 

to emission limits for mercury, HCl, or 

TSM in Tables 1 and 2 or 11 through 13 

to this subpart. Gaseous and liquid fuels 

are exempt from the sampling 

requirements in paragraphs (c) and (d) 

of this section and Table 6 to this 

subpart. 

(b) You must develop a site-specific 

fuel monitoring plan according to the 

following procedures and requirements 

in paragraphs (b)(1) and (2) of this 

section, if you are required to conduct 

fuel analyses as specified in § 63.7510. 

(1) If you intend to use an alternative 

analytical method other than those 

required by Table 6 to this subpart, you 

must submit the fuel analysis plan to 

the Administrator for review and 

approval no later than 60 days before 

the date that you intend to conduct the 

initial compliance demonstration 

described in § 63.7510. 

(2) You must include the information 

contained in paragraphs (b)(2)(i) 

through (vi) of this section in your fuel 

analysis plan. 

(i) The identification of all fuel types 

anticipated to be burned in each boiler 

or process heater. 

(ii) For each anticipated fuel type, the 

notification of whether you or a fuel 

supplier will be conducting the fuel 

analysis. 

(iii) For each anticipated fuel type, a 

detailed description of the sample 

location and specific procedures to be 

used for collecting and preparing the 

composite samples if your procedures 

are different from paragraph (c) or (d) of 

this section. Samples should be 

collected at a location that most 

accurately represents the fuel type, 

where possible, at a point prior to 

mixing with other dissimilar fuel types. 

(iv) For each anticipated fuel type, the 

analytical methods from Table 6, with 

the expected minimum detection levels, 

to be used for the measurement of 

chlorine or mercury. 

(v) If you request to use an alternative 

analytical method other than those 

required by Table 6 to this subpart, you 

must also include a detailed description 

of the methods and procedures that you 

are proposing to use. Methods in Table 

6 shall be used until the requested 

alternative is approved. 

(vi) If you will be using fuel analysis 

from a fuel supplier in lieu of sitespecific sampling and analysis, the fuel 

supplier must use the analytical 

methods required by Table 6 to this 

subpart. 

(c) At a minimum, you must obtain 

three composite fuel samples for each 

fuel type according to the procedures in 

paragraph (c)(1) or (2) of this section, or 

the methods listed in Table 6 to this 

subpart, or use an automated sampling 

mechanism that provides representative 

composite fuel samples for each fuel 

type that includes both coarse and fine 

material. 

(1) If sampling from a belt (or screw) 

feeder, collect fuel samples according to 

paragraphs (c)(1)(i) and (ii) of this 

section. 

(i) Stop the belt and withdraw a 6- 

inch wide sample from the full crosssection of the stopped belt to obtain a 

minimum two pounds of sample. You 

must collect all the material (fines and 

coarse) in the full cross-section. You 

must transfer the sample to a clean 

plastic bag. 

(ii) Each composite sample will 

consist of a minimum of three samples 

collected at approximately equal onehour intervals during the testing period 

for sampling during performance stack 

testing. For monthly sampling, each 

composite sample shall be collected at 

approximately equal 10-day intervals 

during the month. 

(2) If sampling from a fuel pile or 

truck, you must collect fuel samples 

according to paragraphs (c)(2)(i) through 

(iii) of this section. 

(i) For each composite sample, you 

must select a minimum of five sampling 

locations uniformly spaced over the 

surface of the pile. 

(ii) At each sampling site, you must 

dig into the pile to a uniform depth of 

approximately 18 inches. You must 

insert a clean shovel into the hole and 

withdraw a sample, making sure that 

large pieces do not fall off during 

sampling; use the same shovel to collect 

all samples. 

(iii) You must transfer all samples to 

a clean plastic bag for further 

processing. 

(d) You must prepare each composite 

sample according to the procedures in 

paragraphs (d)(1) through (7) of this 

section. 

(1) You must thoroughly mix and 

pour the entire composite sample over 

a clean plastic sheet. 

(2) You must break large sample 

pieces (e.g., larger than 3 inches) into 

smaller sizes. 

(3) You must make a pie shape with 

the entire composite sample and 

subdivide it into four equal parts. 

(4) You must separate one of the 

quarter samples as the first subset. 

(5) If this subset is too large for 

grinding, you must repeat the procedure 

in paragraph (d)(3) of this section with 

the quarter sample and obtain a onequarter subset from this sample. 

(6) You must grind the sample in a 

mill. 

(7) You must use the procedure in 

paragraph (d)(3) of this section to obtain 

a one-quarter subsample for analysis. If 

the quarter sample is too large, 

subdivide it further using the same 

procedure. 

(e) You must determine the 

concentration of pollutants in the fuel 

(mercury and/or chlorine and/or TSM) 

in units of pounds per million Btu of 

each composite sample for each fuel 

type according to the procedures in 


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Table 6 to this subpart, for use in 

Equations 7, 8, and 9 of this subpart. 

(f) To demonstrate that a gaseous fuel 

other than natural gas or refinery gas 

qualifies as an other gas 1 fuel, as 

defined in § 63.7575, you must conduct 

a fuel specification analyses for mercury 

according to the procedures in 

paragraphs (g) through (i) of this section 

and Table 6 to this subpart, as 

applicable, except as specified in 

paragraph (f)(1) through (4) of this 

section. 

(1) You are not required to conduct 

the fuel specification analyses in 

paragraphs (g) through (i) of this section 

for natural gas or refinery gas. 

(2) You are not required to conduct 

the fuel specification analyses in 

paragraphs (g) through (i) of this section 

for gaseous fuels that are subject to 

another subpart of this part, part 60, part 

61, or part 65. 

(3) You are not required to conduct 

the fuel specification analyses in 

paragraphs (g) through (i) of this section 

on gaseous fuels for units that are 

complying with the limits for units 

designed to burn gas 2 (other) fuels. 

(4) You are not required to conduct 

the fuel specification analyses in 

paragraphs (g) through (i) of this section 

for gas streams directly derived from 

natural gas at natural gas production 

sites or natural gas plants. 

(g) You must develop and submit a 

site-specific fuel analysis plan for other 

gas 1 fuels to the EPA Administrator for 

review and approval according to the 

following procedures and requirements 

in paragraphs (g)(1) and (2) of this 

section. 

(1) If you intend to use an alternative 

analytical method other than those 

required by Table 6 to this subpart, you 

must submit the fuel analysis plan to 

the Administrator for review and 

approval no later than 60 days before 

the date that you intend to conduct the 

initial compliance demonstration 

described in § 63.7510. 

(2) You must include the information 

contained in paragraphs (g)(2)(i) through 

(vi) of this section in your fuel analysis 

plan. 

(i) The identification of all gaseous 

fuel types other than those exempted 

from fuel specification analysis under 

(f)(1) through (3) of this section 

anticipated to be burned in each boiler 

or process heater. 

(ii) For each anticipated fuel type, the 

notification of whether you or a fuel 

supplier will be conducting the fuel 

specification analysis. 

(iii) For each anticipated fuel type, a 

detailed description of the sample 

location and specific procedures to be 

used for collecting and preparing the 

samples if your procedures are different 

from the sampling methods contained in 

Table 6 to this subpart. Samples should 

be collected at a location that most 

accurately represents the fuel type, 

where possible, at a point prior to 

mixing with other dissimilar fuel types. 

If multiple boilers or process heaters are 

fueled by a common fuel stream it is 

permissible to conduct a single gas 

specification at the common point of gas 

distribution. 

(iv) For each anticipated fuel type, the 

analytical methods from Table 6 to this 

subpart, with the expected minimum 

detection levels, to be used for the 

measurement of mercury. 

(v) If you request to use an alternative 

analytical method other than those 

required by Table 6 to this subpart, you 

must also include a detailed description 

of the methods and procedures that you 

are proposing to use. Methods in Table 

6 to this subpart shall be used until the 

requested alternative is approved. 

(vi) If you will be using fuel analysis 

from a fuel supplier in lieu of sitespecific sampling and analysis, the fuel 

supplier must use the analytical 

methods required by Table 6 to this 

subpart. 

(h) You must obtain a single fuel 

sample for each fuel type according to 

the sampling procedures listed in Table 

6 for fuel specification of gaseous fuels. 

(i) You must determine the 

concentration in the fuel of mercury, in 

units of microgram per cubic meter, dry 

basis, of each sample for each other gas 

1 fuel type according to the procedures 

in Table 6 to this subpart. 

■ 16. Section § 63.7522 is revised by: 

■ a. Revising paragraphs (a) through (d). 

■ b. Revising paragraphs (e)(1) and (2). 

■ c. Revising paragraphs (f) introductory 

text and (f)(1) and (2). 

■ d. Revising paragraphs (g) 

introductory text, (g)(2)(i), (g)(2)(iv), 

(g)(2)(vi)(B), (g)(3) introductory text, 

(g)(4) introductory text, and (g)(4)(ii). 

■ e. Revising paragraph (h). 

■ f. Revising paragraph (i). 

■ g. Revising paragraph (j)(1). 

■ h. Revising paragraph (k). 

The revisions read as follows: 

§ 63.7522 Can I use emissions averaging 

to comply with this subpart? 

(a) As an alternative to meeting the 

requirements of § 63.7500 for PM (or 

TSM), HCl, or mercury on a boiler or 

process heater-specific basis, if you have 

more than one existing boiler or process 

heater in any subcategories located at 

your facility, you may demonstrate 

compliance by emissions averaging, if 

your averaged emissions are not more 

than 90 percent of the applicable 

emission limit, according to the 

procedures in this section. You may not 

include new boilers or process heaters 

in an emissions average. 

(b) For a group of two or more existing 

boilers or process heaters in the same 

subcategory that each vent to a separate 

stack, you may average PM (or TSM), 

HCl, or mercury emissions among 

existing units to demonstrate 

compliance with the limits in Table 2 to 

this subpart as specified in paragraph 

(b)(1) through (3) of this section, if you 

satisfy the requirements in paragraphs 

(c) through (g) of this section. 

(1) You may average units using a 

CEMS or PM CPMS for demonstrating 

compliance. 

(2) For mercury and HCl, averaging is 

allowed as follows: 

(i) You may average among units in 

any of the solid fuel subcategories. 

(ii) You may average among units in 

any of the liquid fuel subcategories. 

(iii) You may average among units in 

a subcategory of units designed to burn 

gas 2 (other) fuels. 

(iv) You may not average across the 

units designed to burn liquid, units 

designed to burn solid fuel, and units 

designed to burn gas 2 (other) 

subcategories. 

(3) For PM (or TSM), averaging is only 

allowed between units within each of 

the following subcategories and you 

may not average across subcategories: 

(i) Units designed to burn coal/solid 

fossil fuel. 

(ii) Stokers/sloped grate/other units 

designed to burn kiln dried biomass/ 

bio-based solids. 

(iii) Stokers/sloped grate/other units 

designed to burn wet biomass/bio-based 

solids. 

(iv) Fluidized bed units designed to 

burn biomass/bio-based solid. 

(v) Suspension burners designed to 

burn biomass/bio-based solid. 

(vi) Dutch ovens/pile burners 

designed to burn biomass/bio-based 

solid. 

(vii) Fuel Cells designed to burn 

biomass/bio-based solid. 

(viii) Hybrid suspension/grate burners 

designed to burn wet biomass/bio-based 

solid. 

(ix) Units designed to burn heavy 

liquid fuel. 

(x) Units designed to burn light liquid 

fuel. 

(xi) Units designed to burn liquid fuel 

that are non-continental units. 

(xii) Units designed to burn gas 2 

(other) gases. 

(c) For each existing boiler or process 

heater in the averaging group, the 

emission rate achieved during the initial 

compliance test for the HAP being 

averaged must not exceed the emission 

level that was being achieved on 


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January 31, 2013 or the control 

technology employed during the initial 

compliance test must not be less 

effective for the HAP being averaged 

than the control technology employed 

on January 31, 2013. 

(d) The averaged emissions rate from 

the existing boilers and process heaters 

participating in the emissions averaging 

option must not exceed 90 percent of 

the limits in Table 2 to this subpart at 

all times the affected units are operating 

following the compliance date specified 

in § 63.7495. 

(e) * * * 

(1) You must use Equation 1a or 1b or 

1c of this section to demonstrate that the 

PM (or TSM), HCl, or mercury 

emissions from all existing units 

participating in the emissions averaging 

option for that pollutant do not exceed 

the emission limits in Table 2 to this 

subpart. Use Equation 1a if you are 

complying with the emission limits on 

a heat input basis, use Equation 1b if 

you are complying with the emission 

limits on a steam generation (output) 

basis, and use Equation 1c if you are 

complying with the emission limits on 

a electric generation (output) basis. 

Where: 

AveWeightedEmissions = Average weighted 

emissions for PM (or TSM), HCl, or 

mercury, in units of pounds per million 

Btu of heat input. 

Er = Emission rate (as determined during the 

initial compliance demonstration) of PM 

(or TSM), HCl, or mercury from unit, i, 

in units of pounds per million Btu of 

heat input. Determine the emission rate 

for PM (or TSM), HCl, or mercury by 

performance testing according to Table 5 

to this subpart, or by fuel analysis for 

HCl or mercury or TSM using the 

applicable equation in § 63.7530(c). 

Hm = Maximum rated heat input capacity of 

unit, i, in units of million Btu per hour. 

n = Number of units participating in the 

emissions averaging option. 

1.1 = Required discount factor. 

Where: 

AveWeightedEmissions = Average weighted 

emissions for PM (or TSM), HCl, or 

mercury, in units of pounds per million 

Btu of steam output. 

Er = Emission rate (as determined during the 

initial compliance demonstration) of PM 

(or TSM), HCl, or mercury from unit, i, 

in units of pounds per million Btu of 

steam output. Determine the emission 

rate for PM (or TSM), HCl, or mercury by 

performance testing according to Table 5 

to this subpart, or by fuel analysis for 

HCl or mercury or TSM using the 

applicable equation in § 63.7530(c). If 

you are taking credit for energy 

conservation measures from a unit 

according to § 63.7533, use the adjusted 

emission level for that unit, Eadj, 

determined according to § 63.7533 for 

that unit. 

So = Maximum steam output capacity of 

unit, i, in units of million Btu per hour, 

as defined in § 63.7575. 

n = Number of units participating in the 

emissions averaging option. 

1.1 = Required discount factor. 

Where: 

AveWeightedEmissions = Average weighted 

emissions for PM (or TSM), HCl, or 

mercury, in units of pounds per 

megawatt hour. 

Er = Emission rate (as determined during the 

initial compliance demonstration) of PM 

(or TSM), HCl, or mercury from unit, i, 

in units of pounds per megawatt hour. 

Determine the emission rate for PM (or 

TSM), HCl, or mercury by performance 

testing according to Table 5 to this 

subpart, or by fuel analysis for HCl or 

mercury or TSM using the applicable 

equation in § 63.7530(c). If you are taking 

credit for energy conservation measures 

from a unit according to § 63.7533, use 

the adjusted emission level for that unit, 

Eadj, determined according to § 63.7533 

for that unit. 

Eo = Maximum electric generating output 

capacity of unit, i, in units of megawatt 

hour, as defined in § 63.7575. 

n = Number of units participating in the 

emissions averaging option. 

1.1 = Required discount factor. 

(2) If you are not capable of 

determining the maximum rated heat 

input capacity of one or more boilers 

that generate steam, you may use 

Equation 2 of this section as an 

alternative to using Equation 1a of this 

section to demonstrate that the PM (or 

TSM), HCl, or mercury emissions from 

all existing units participating in the 

emissions averaging option do not 

exceed the emission limits for that 

pollutant in Table 2 to this subpart that 

are in pounds per million Btu of heat 

input. 

Where: 

AveWeightedEmissions = Average weighted 

emission level for PM (or TSM), HCl, or 

mercury, in units of pounds per million 

Btu of heat input. 

Er = Emission rate (as determined during the 

most recent compliance demonstration) 

of PM (or TSM), HCl, or mercury from 

unit, i, in units of pounds per million 

Btu of heat input. Determine the 

emission rate for PM (or TSM), HCl, or 

mercury by performance testing 

according to Table 5 to this subpart, or 

by fuel analysis for HCl or mercury or 

TSM using the applicable equation in 

§ 63.7530(c). 


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7170 Federal Register / Vol. 78, No. 21 / Thursday, January 31, 2013 / Rules and Regulations 

Sm = Maximum steam generation capacity by 

unit, i, in units of pounds per hour. 

Cfi = Conversion factor, calculated from the 

most recent compliance test, in units of 

million Btu of heat input per pounds of 

steam generated for unit, i. 

1.1 = Required discount factor. 

(f) After the initial compliance 

demonstration described in paragraph 

(e) of this section, you must demonstrate 

compliance on a monthly basis 

determined at the end of every month 

(12 times per year) according to 

paragraphs (f)(1) through (3) of this 

section. The first monthly period begins 

on the compliance date specified in 

§ 63.7495. If the affected source elects to 

collect monthly data for up the 11 

months preceding the first monthly 

period, these additional data points can 

be used to compute the 12-month 

rolling average in paragraph (f)(3) of this 

section. 

(1) For each calendar month, you 

must use Equation 3a or 3b or 3c of this 

section to calculate the average 

weighted emission rate for that month. 

Use Equation 3a and the actual heat 

input for the month for each existing 

unit participating in the emissions 

averaging option if you are complying 

with emission limits on a heat input 

basis. Use Equation 3b and the actual 

steam generation for the month if you 

are complying with the emission limits 

on a steam generation (output) basis. 

Use Equation 3c and the actual steam 

generation for the month if you are 

complying with the emission limits on 

a electrical generation (output) basis. 

Where: 

AveWeightedEmissions = Average weighted 

emission level for PM (or TSM), HCl, or 

mercury, in units of pounds per million 

Btu of heat input, for that calendar 

month. 

Er = Emission rate (as determined during the 

most recent compliance demonstration) 

of PM (or TSM), HCl, or mercury from 

unit, i, in units of pounds per million 

Btu of heat input. Determine the 

emission rate for PM (or TSM), HCl, or 

mercury by performance testing 

according to Table 5 to this subpart, or 

by fuel analysis for HCl or mercury or 

TSM according to Table 6 to this subpart. 

Hb = The heat input for that calendar month 

to unit, i, in units of million Btu. 

n = Number of units participating in the 

emissions averaging option. 

1.1 = Required discount factor. 

Where: 

AveWeightedEmissions = Average weighted 

emission level for PM (or TSM), HCl, or 

mercury, in units of pounds per million 

Btu of steam output, for that calendar 

month. 

Er = Emission rate (as determined during the 

most recent compliance demonstration) 

of PM (or TSM), HCl, or mercury from 

unit, i, in units of pounds per million 

Btu of steam output. Determine the 

emission rate for PM (or TSM), HCl, or 

mercury by performance testing 

according to Table 5 to this subpart, or 

by fuel analysis for HCl or mercury or 

TSM according to Table 6 to this subpart. 

If you are taking credit for energy 

conservation measures from a unit 

according to § 63.7533, use the adjusted 

emission level for that unit, Eadj, 

determined according to § 63.7533 for 

that unit. 

So = The steam output for that calendar 

month from unit, i, in units of million 

Btu, as defined in § 63.7575. 

n = Number of units participating in the 

emissions averaging option. 

1.1 = Required discount factor. 

Where: 

AveWeightedEmissions = Average weighted 

emission level for PM (or TSM), HCl, or 

mercury, in units of pounds per 

megawatt hour, for that calendar month. 

Er = Emission rate (as determined during the 

most recent compliance demonstration) 

of PM (or TSM), HCl, or mercury from 

unit, i, in units of pounds per megawatt 

hour. Determine the emission rate for PM 

(or TSM), HCl, or mercury by 

performance testing according to Table 5 

to this subpart, or by fuel analysis for 

HCl or mercury or TSM according to 

Table 6 to this subpart. If you are taking 

credit for energy conservation measures 

from a unit according to § 63.7533, use 

the adjusted emission level for that unit, 

Eadj, determined according to § 63.7533 

for that unit. 

Eo = The electric generating output for that 

calendar month from unit, i, in units of 

megawatt hour, as defined in § 63.7575. 

n = Number of units participating in the 

emissions averaging option. 

1.1 = Required discount factor. 

(2) If you are not capable of 

monitoring heat input, you may use 

Equation 4 of this section as an 

alternative to using Equation 3a of this 

section to calculate the average 

weighted emission rate using the actual 

steam generation from the boilers 

participating in the emissions averaging 

option. 

Where: AveWeightedEmissions = average weighted 

emission level for PM (or TSM), HCl, or 

mercury, in units of pounds per million 


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Federal Register / Vol. 78, No. 21 / Thursday, January 31, 2013 / Rules and Regulations 7171 

Btu of heat input for that calendar 

month. 

Er = Emission rate (as determined during the 

most recent compliance demonstration 

of PM (or TSM), HCl, or mercury from 

unit, i, in units of pounds per million 

Btu of heat input. Determine the 

emission rate for PM (or TSM), HCl, or 

mercury by performance testing 

according to Table 5 to this subpart, or 

by fuel analysis for HCl or mercury or 

TSM according to Table 6 to this subpart. 

Sa = Actual steam generation for that 

calendar month by boiler, i, in units of 

pounds. 

Cfi = Conversion factor, as calculated during 

the most recent compliance test, in units 

of million Btu of heat input per pounds 

of steam generated for boiler, i. 

1.1 = Required discount factor. 

* * * * * 

(g) You must develop, and submit 

upon request to the applicable 

Administrator for review and approval, 

an implementation plan for emission 

averaging according to the following 

procedures and requirements in 

paragraphs (g)(1) through (4) of this 

section. 

* * * * * 

(2) * * * 

(i) The identification of all existing 

boilers and process heaters in the 

averaging group, including for each 

either the applicable HAP emission 

level or the control technology installed 

as of January 31, 2013 and the date on 

which you are requesting emission 

averaging to commence; 

* * * * * 

(iv) The test plan for the measurement 

of PM (or TSM), HCl, or mercury 

emissions in accordance with the 

requirements in § 63.7520; 

* * * * * 

(vi) * * * 

(B) A description of the methods and 

procedures that will be used to 

demonstrate that the parameter 

indicates proper operation of the control 

device; the frequency and content of 

monitoring, reporting, and 

recordkeeping requirements; and a 

demonstration, to the satisfaction of the 

Administrator, that the proposed 

monitoring frequency is sufficient to 

represent control device operating 

conditions; and 

* * * * * 

(3) The Administrator shall review 

and approve or disapprove the plan 

according to the following criteria: 

* * * * * 

(4) The applicable Administrator shall 

not approve an emission averaging 

implementation plan containing any of 

the following provisions: 

* * * * * 

(ii) The inclusion of any emission 

source other than an existing unit in the 

same subcategories. 

* * * * * 

(h) For a group of two or more 

existing affected units, each of which 

vents through a single common stack, 

you may average PM (or TSM), HCl, or 

mercury emissions to demonstrate 

compliance with the limits for that 

pollutant in Table 2 to this subpart if 

you satisfy the requirements in 

paragraph (i) or (j) of this section. 

(i) For a group of two or more existing 

units in the same subcategories, each of 

which vents through a common 

emissions control system to a common 

stack, that does not receive emissions 

from units in other subcategories or 

categories, you may treat such averaging 

group as a single existing unit for 

purposes of this subpart and comply 

with the requirements of this subpart as 

if the group were a single unit. 

(j) * * * 

(1) Conduct performance tests 

according to procedures specified in 

§ 63.7520 in the common stack if 

affected units from other subcategories 

vent to the common stack. The emission 

limits that the group must comply with 

are determined by the use of Equation 

6 of this section. 

Where: 

En = HAP emission limit, pounds per million 

British thermal units (lb/MMBtu), parts 

per million (ppm), or nanograms per dry 

standard cubic meter (ng/dscm). 

ELi = Appropriate emission limit from Table 

2 to this subpart for unit i, in units of lb/ 

MMBtu, ppm or ng/dscm. 

Hi = Heat input from unit i, MMBtu. 

* * * * * 

(k) The common stack of a group of 

two or more existing boilers or process 

heaters in the same subcategories 

subject to paragraph (h) of this section 

may be treated as a separate stack for 

purposes of paragraph (b) of this section 

and included in an emissions averaging 

group subject to paragraph (b) of this 

section. 

■ 17. Section 63.7525 is amended by: 

■ a. Revising paragraph (a) 

■ b. Revising paragraph (b). 

■ c. Revising paragraph (c) introductory 

text. 

■ d. Revising paragraphs (d) 

introductory text and paragraphs (d)(1) 

through (d)(4). 

■ e. Revising paragraph (e)(2). 

■ f. Revising paragraph (e)(3). 

■ g. Revising paragraph (f)(2). 

■ h. Revising paragraph (j). 

■ i. Revising paragraph (k). 

■ j. Adding paragraph (l). 

■ k. Adding paragraph (m). 

The revisions and additions read as 

follows: 

§ 63.7525 What are my monitoring, 

installation, operation, and maintenance 

requirements? 

(a) If your boiler or process heater is 

subject to a CO emission limit in Tables 

1, 2, or 11 through 13 to this subpart, 

you must install, operate, and maintain 

an oxygen analyzer system, as defined 

in § 63.7575, or install, certify, operate 

and maintain continuous emission 

monitoring systems for CO and oxygen 

according to the procedures in 

paragraphs (a)(1) through (7) of this 

section. 

(1) Install the CO CEMS and oxygen 

analyzer by the compliance date 

specified in § 63.7495. The CO and 

oxygen levels shall be monitored at the 

same location at the outlet of the boiler 

or process heater. 

(2) To demonstrate compliance with 

the applicable alternative CO CEMS 

emission standard listed in Tables 1, 2, 

or 11 through 13 to this subpart, you 

must install, certify, operate, and 

maintain a CO CEMS and an oxygen 

analyzer according to the applicable 

procedures under Performance 

Specification 4, 4A, or 4B at 40 CFR part 

60, appendix B, the site-specific 

monitoring plan developed according to 

§ 63.7505(d), and the requirements in 

§ 63.7540(a)(8) and paragraph (a) of this 

section. Any boiler or process heater 

that has a CO CEMS that is compliant 

with Performance Specification 4, 4A, 

or 4B at 40 CFR part 60, appendix B, a 

site-specific monitoring plan developed 

according to § 63.7505(d), and the 

requirements in § 63.7540(a)(8) and 

paragraph (a) of this section must use 

the CO CEMS to comply with the 

applicable alternative CO CEMS 

emission standard listed in Tables 1, 2, 

or 11 through 13 to this subpart. 

(i) You must conduct a performance 

evaluation of each CO CEMS according 

to the requirements in § 63.8(e) and 


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according to Performance Specification 

4, 4A, or 4B at 40 CFR part 60, appendix 

B. 

(ii) During each relative accuracy test 

run of the CO CEMS, you must be 

collect emission data for CO 

concurrently (or within a 30- to 60- 

minute period) by both the CO CEMS 

and by Method 10, 10A, or 10B at 40 

CFR part 60, appendix A–4. The relative 

accuracy testing must be at 

representative operating conditions. 

(iii) You must follow the quality 

assurance procedures (e.g., quarterly 

accuracy determinations and daily 

calibration drift tests) of Procedure 1 of 

appendix F to part 60. The measurement 

span value of the CO CEMS must be two 

times the applicable CO emission limit, 

expressed as a concentration. 

(iv) Any CO CEMS that does not 

comply with § 63.7525(a) cannot be 

used to meet any requirement in this 

subpart to demonstrate compliance with 

a CO emission limit listed in Tables 1, 

2, or 11 through 13 to this subpart. 

(v) For a new unit, complete the 

initial performance evaluation no later 

than July 30, 2013, or 180 days after the 

date of initial startup, whichever is 

later. For an existing unit, complete the 

initial performance evaluation no later 

than July 29, 2016. 

(3) Complete a minimum of one cycle 

of CO and oxygen CEMS operation 

(sampling, analyzing, and data 

recording) for each successive 15- 

minute period. Collect CO and oxygen 

data concurrently. Collect at least four 

CO and oxygen CEMS data values 

representing the four 15-minute periods 

in an hour, or at least two 15-minute 

data values during an hour when CEMS 

calibration, quality assurance, or 

maintenance activities are being 

performed. 

(4) Reduce the CO CEMS data as 

specified in § 63.8(g)(2). 

(5) Calculate one-hour arithmetic 

averages, corrected to 3 percent oxygen 

from each hour of CO CEMS data in 

parts per million CO concentration. The 

one-hour arithmetic averages required 

shall be used to calculate the 30-day or 

10-day rolling average emissions. Use 

Equation 19–19 in section 12.4.1 of 

Method 19 of 40 CFR part 60, appendix 

A–7 for calculating the average CO 

concentration from the hourly values. 

(6) For purposes of collecting CO data, 

operate the CO CEMS as specified in 

§ 63.7535(b). You must use all the data 

collected during all periods in 

calculating data averages and assessing 

compliance, except that you must 

exclude certain data as specified in 

§ 63.7535(c). Periods when CO data are 

unavailable may constitute monitoring 

deviations as specified in § 63.7535(d). 

(7) Operate an oxygen trim system 

with the oxygen level set no lower than 

the lowest hourly average oxygen 

concentration measured during the most 

recent CO performance test as the 

operating limit for oxygen according to 

Table 7 to this subpart. 

(b) If your boiler or process heater is 

in the unit designed to burn coal/solid 

fossil fuel subcategory or the unit 

designed to burn heavy liquid 

subcategory and has an average annual 

heat input rate greater than 250 MMBtu 

per hour from solid fossil fuel and/or 

heavy liquid, and you demonstrate 

compliance with the PM limit instead of 

the alternative TSM limit, you must 

install, certify, maintain, and operate a 

PM CPMS monitoring emissions 

discharged to the atmosphere and 

record the output of the system as 

specified in paragraphs (b)(1) through 

(4) of this section. As an alternative to 

use of a PM CPMS to demonstrate 

compliance with the PM limit, you may 

choose to use a PM CEMS. If you choose 

to use a PM CEMS to demonstrate 

compliance with the PM limit instead of 

the alternative TSM limit, you must 

install, certify, maintain, and operate a 

PM CEMS monitoring emissions 

discharged to the atmosphere and 

record the output of the system as 

specified in paragraph (b)(5) through (8) 

of this section. For other boilers or 

process heaters, you may elect to use a 

PM CPMS or PM CEMS operated in 

accordance with this section in lieu of 

using other CMS for monitoring PM 

compliance (e.g., bag leak detectors, ESP 

secondary power, PM scrubber 

pressure). Owners of boilers and process 

heaters who elect to comply with the 

alternative TSM limit are not required to 

install a PM CPMS. 

(1) Install, certify, operate, and 

maintain your PM CPMS according to 

the procedures in your approved sitespecific monitoring plan developed in 

accordance with § 63.7505(d), the 

requirements in § 63.7540(a)(9), and 

paragraphs (b)(1)(i) through (iii) of this 

section. 

(i) The operating principle of the PM 

CPMS must be based on in-stack or 

extractive light scatter, light 

scintillation, beta attenuation, or mass 

accumulation detection of PM in the 

exhaust gas or representative exhaust 

gas sample. The reportable 

measurement output from the PM CPMS 

must be expressed as milliamps. 

(ii) The PM CPMS must have a cycle 

time (i.e., period required to complete 

sampling, measurement, and reporting 

for each measurement) no longer than 

60 minutes. 

(iii) The PM CPMS must be capable of 

detecting and responding to PM 

concentrations of no greater than 0.5 

milligram per actual cubic meter. 

(2) For a new unit, complete the 

initial performance evaluation no later 

than July 30, 2013, or 180 days after the 

date of initial startup, whichever is 

later. For an existing unit, complete the 

initial performance evaluation no later 

than July 29, 2016. 

(3) Collect PM CPMS hourly average 

output data for all boiler or process 

heater operating hours except as 

indicated in § 63.7535(a) through (d). 

Express the PM CPMS output as 

milliamps. 

(4) Calculate the arithmetic 30-day 

rolling average of all of the hourly 

average PM CPMS output data collected 

during all boiler or process heater 

operating hours (milliamps). 

(5) Install, certify, operate, and 

maintain your PM CEMS according to 

the procedures in your approved sitespecific monitoring plan developed in 

accordance with § 63.7505(d), the 

requirements in § 63.7540(a)(9), and 

paragraphs (b)(5)(i) through (iv) of this 

section. 

(i) You shall conduct a performance 

evaluation of the PM CEMS according to 

the applicable requirements of § 60.8(e), 

and Performance Specification 11 at 40 

CFR part 60, appendix B of this chapter. 

(ii) During each PM correlation testing 

run of the CEMS required by 

Performance Specification 11 at 40 CFR 

part 60, appendix B of this chapter, you 

shall collect PM and oxygen (or carbon 

dioxide) data concurrently (or within a 

30-to 60-minute period) by both the 

CEMS and conducting performance tests 

using Method 5 at 40 CFR part 60, 

appendix A–3 or Method 17 at 40 CFR 

part 60, appendix A–6 of this chapter. 

(iii) You shall perform quarterly 

accuracy determinations and daily 

calibration drift tests in accordance with 

Procedure 2 at 40 CFR part 60, appendix 

F of this chapter. You must perform 

Relative Response Audits annually and 

perform Response Correlation Audits 

every 3 years. 

(iv) Within 60 days after the date of 

completing each CEMS relative 

accuracy test audit or performance test 

conducted to demonstrate compliance 

with this subpart, you must submit the 

relative accuracy test audit data and 

performance test data to the EPA by 

successfully submitting the data 

electronically into the EPA’s Central 

Data Exchange by using the Electronic 

Reporting Tool (see http://www.epa.gov/ 

ttn/chief/ert/erttool.html/). 

(6) For a new unit, complete the 

initial performance evaluation no later 

than July 30, 2013, or 180 days after the 

date of initial startup, whichever is 

later. For an existing unit, complete the 


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initial performance evaluation no later 

than July 29, 2016. 

(7) Collect PM CEMS hourly average 

output data for all boiler or process 

heater operating hours except as 

indicated in § 63.7535(a) through (d). 

(8) Calculate the arithmetic 30-day 

rolling average of all of the hourly 

average PM CEMS output data collected 

during all boiler or process heater 

operating hours. 

(c) If you have an applicable opacity 

operating limit in this rule, and are not 

otherwise required or elect to install and 

operate a PM CPMS, PM CEMS, or a bag 

leak detection system, you must install, 

operate, certify and maintain each 

COMS according to the procedures in 

paragraphs (c)(1) through (7) of this 

section by the compliance date specified 

in § 63.7495. 

* * * * * 

(d) If you have an operating limit that 

requires the use of a CMS other than a 

PM CPMS or COMS, you must install, 

operate, and maintain each CMS 

according to the procedures in 

paragraphs (d)(1) through (5) of this 

section by the compliance date specified 

in § 63.7495. 

(1) The CPMS must complete a 

minimum of one cycle of operation 

every 15-minutes. You must have a 

minimum of four successive cycles of 

operation, one representing each of the 

four 15-minute periods in an hour, to 

have a valid hour of data. 

(2) You must operate the monitoring 

system as specified in § 63.7535(b), and 

comply with the data calculation 

requirements specified in § 63.7535(c). 

(3) Any 15-minute period for which 

the monitoring system is out-of-control 

and data are not available for a required 

calculation constitutes a deviation from 

the monitoring requirements. Other 

situations that constitute a monitoring 

deviation are specified in § 63.7535(d). 

(4) You must determine the 30-day 

rolling average of all recorded readings, 

except as provided in § 63.7535(c). 

* * * * * 

(e) * * * 

(2) You must use a flow sensor with 

a measurement sensitivity of no greater 

than 2 percent of the design flow rate. 

(3) You must minimize, consistent 

with good engineering practices, the 

effects of swirling flow or abnormal 

velocity distributions due to upstream 

and downstream disturbances. 

* * * * * 

(f) * * * 

(2) Minimize or eliminate pulsating 

pressure, vibration, and internal and 

external corrosion consistent with good 

engineering practices. 

* * * * * 

(j) If you are not required to use a PM 

CPMS and elect to use a fabric filter bag 

leak detection system to comply with 

the requirements of this subpart, you 

must install, calibrate, maintain, and 

continuously operate the bag leak 

detection system as specified in 

paragraphs (j)(1) through (6) of this 

section. 

(1) You must install a bag leak 

detection sensor(s) in a position(s) that 

will be representative of the relative or 

absolute PM loadings for each exhaust 

stack, roof vent, or compartment (e.g., 

for a positive pressure fabric filter) of 

the fabric filter. 

(2) Conduct a performance evaluation 

of the bag leak detection system in 

accordance with your monitoring plan 

and consistent with the guidance 

provided in EPA–454/R–98–015 

(incorporated by reference, see § 63.14). 

(3) Use a bag leak detection system 

certified by the manufacturer to be 

capable of detecting PM emissions at 

concentrations of 10 milligrams per 

actual cubic meter or less. 

(4) Use a bag leak detection system 

equipped with a device to record 

continuously the output signal from the 

sensor. 

(5) Use a bag leak detection system 

equipped with a system that will alert 

plant operating personnel when an 

increase in relative PM emissions over 

a preset level is detected. The alert must 

easily recognizable (e.g., heard or seen) 

by plant operating personnel. 

(6) Where multiple bag leak detectors 

are required, the system’s 

instrumentation and alert may be shared 

among detectors. 

(k) For each unit that meets the 

definition of limited-use boiler or 

process heater, you must keep fuel use 

records for the days the boiler or process 

heater was operating. 

(l) For each unit for which you decide 

to demonstrate compliance with the 

mercury or HCl emissions limits in 

Tables 1 or 2 or 11 through 13 of this 

subpart by use of a CEMS for mercury 

or HCl, you must install, certify, 

maintain, and operate a CEMS 

measuring emissions discharged to the 

atmosphere and record the output of the 

system as specified in paragraphs (l)(1) 

through (8) of this section. For HCl, this 

option for an affected unit takes effect 

on the date a final performance 

specification for a HCl CEMS is 

published in the Federal Register or the 

date of approval of a site-specific 

monitoring plan. 

(1) Notify the Administrator one 

month before starting use of the CEMS, 

and notify the Administrator one month 

before stopping use of the CEMS. 

(2) Each CEMS shall be installed, 

certified, operated, and maintained 

according to the requirements in 

§ 63.7540(a)(14) for a mercury CEMS 

and § 63.7540(a)(15) for a HCl CEMS. 

(3) For a new unit, you must complete 

the initial performance evaluation of the 

CEMS by the latest of the dates specified 

in paragraph (l)(3)(i) through (iii) of this 

section. 

(i) No later than July 30, 2013. 

(ii) No later 180 days after the date of 

initial startup. 

(iii) No later 180 days after notifying 

the Administrator before starting to use 

the CEMS in place of performance 

testing or fuel analysis to demonstrate 

compliance. 

(4) For an existing unit, you must 

complete the initial performance 

evaluation by the latter of the two dates 

specified in paragraph (l)(4)(i) and (ii) of 

this section. 

(i) No later than July 29, 2016. 

(ii) No later 180 days after notifying 

the Administrator before starting to use 

the CEMS in place of performance 

testing or fuel analysis to demonstrate 

compliance. 

(5) Compliance with the applicable 

emissions limit shall be determined 

based on the 30-day rolling average of 

the hourly arithmetic average emissions 

rates using the continuous monitoring 

system outlet data. The 30-day rolling 

arithmetic average emission rate (lb/ 

MMBtu) shall be calculated using the 

equations in EPA Reference Method 19 

at 40 CFR part 60, appendix A–7, but 

substituting the mercury or HCl 

concentration for the pollutant 

concentrations normally used in 

Method 19. 

(6) Collect CEMS hourly averages for 

all operating hours on a 30-day rolling 

average basis. Collect at least four CMS 

data values representing the four 15- 

minute periods in an hour, or at least 

two 15-minute data values during an 

hour when CMS calibration, quality 

assurance, or maintenance activities are 

being performed. 

(7) The one-hour arithmetic averages 

required shall be expressed in lb/ 

MMBtu and shall be used to calculate 

the boiler 30-day and 10-day rolling 

average emissions. 

(8) You are allowed to substitute the 

use of the PM, mercury or HCl CEMS for 

the applicable fuel analysis, annual 

performance test, and operating limits 

specified in Table 4 to this subpart to 

demonstrate compliance with the PM, 

mercury or HCl emissions limit, and if 

you are using an acid gas wet scrubber 

or dry sorbent injection control 

technology to comply with the HCl 

emission limit, you are allowed to 

substitute the use of a sulfur dioxide 


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7174 Federal Register / Vol. 78, No. 21 / Thursday, January 31, 2013 / Rules and Regulations 

(SO2) CEMS for the applicable fuel 

analysis, annual performance test, and 

operating limits specified in Table 4 to 

this subpart to demonstrate compliance 

with HCl emissions limit. 

(m) If your unit is subject to a HCl 

emission limit in Tables 1, 2, or 11 

through 13 of this subpart and you have 

an acid gas wet scrubber or dry sorbent 

injection control technology and you 

use an SO2 CEMS, you must install the 

monitor at the outlet of the boiler or 

process heater, downstream of all 

emission control devices, and you must 

install, certify, operate, and maintain 

the CEMS according to part 75 of this 

chapter. 

(1) The SO2 CEMS must be installed 

by the compliance date specified in 

§ 63.7495. 

(2) For on-going quality assurance 

(QA), the SO2 CEMS must meet the 

applicable daily, quarterly, and 

semiannual or annual requirements in 

sections 2.1 through 2.3 of appendix B 

to part 75 of this chapter, with the 

following addition: You must perform 

the linearity checks required in section 

2.2 of appendix B to part 75 of this 

chapter if the SO2 CEMS has a span 

value of 30 ppm or less. 

(3) For a new unit, the initial 

performance evaluation shall be 

completed no later than July 30, 2013, 

or 180 days after the date of initial 

startup, whichever is later. For an 

existing unit, the initial performance 

evaluation shall be completed no later 

than July 29, 2016. 

(4) For purposes of collecting SO2

data, you must operate the SO2 CEMS as 

specified in § 63.7535(b). You must use 

all the data collected during all periods 

in calculating data averages and 

assessing compliance, except that you 

must exclude certain data as specified 

in § 63.7535(c). Periods when SO2 data 

are unavailable may constitute 

monitoring deviations as specified in 

§ 63.7535(d). 

(5) Collect CEMS hourly averages for 

all operating hours on a 30-day rolling 

average basis. 

(6) Use only unadjusted, qualityassured SO2 concentration values in the 

emissions calculations; do not apply 

bias adjustment factors to the part 75 

SO2 data and do not use part 75 

substitute data values. 

■ 18. Section 63.7530 is amended by: 

■ a. Revising paragraph (a). 

■ b. Revising paragraph (b) introductory 

text. 

■ c. Redesignating paragraph (b)(3) as 

paragraph (b)(4) and adding new 

paragraph (b)(3). 

■ d. Revising newly designated 

paragraph (b)(4). 

■ e. Revising paragraph (c), (c)(2) 

through (4). 

■ f. Adding paragraph (c)(5). 

■ g. Revising paragraphs (d), (e), (g), and 

(h). 

■ h. Adding paragraph (i). 

The revisions and additions read as 

follows: 

§ 63.7530 How do I demonstrate initial 

compliance with the emission limitations, 

fuel specifications and work practice 

standards? 

(a) You must demonstrate initial 

compliance with each emission limit 

that applies to you by conducting initial 

performance tests and fuel analyses and 

establishing operating limits, as 

applicable, according to § 63.7520, 

paragraphs (b) and (c) of this section, 

and Tables 5 and 7 to this subpart. The 

requirement to conduct a fuel analysis 

is not applicable for units that burn a 

single type of fuel, as specified by 

§ 63.7510(a)(2)(i). If applicable, you 

must also install, operate, and maintain 

all applicable CMS (including CEMS, 

COMS, and CPMS) according to 

§ 63.7525. 

(b) If you demonstrate compliance 

through performance testing, you must 

establish each site-specific operating 

limit in Table 4 to this subpart that 

applies to you according to the 

requirements in § 63.7520, Table 7 to 

this subpart, and paragraph (b)(4) of this 

section, as applicable. You must also 

conduct fuel analyses according to 

§ 63.7521 and establish maximum fuel 

pollutant input levels according to 

paragraphs (b)(1) through (3) of this 

section, as applicable, and as specified 

in § 63.7510(a)(2). (Note that 

§ 63.7510(a)(2) exempts certain fuels 

from the fuel analysis requirements.) 

However, if you switch fuel(s) and 

cannot show that the new fuel(s) does 

(do) not increase the chlorine, mercury, 

or TSM input into the unit through the 

results of fuel analysis, then you must 

repeat the performance test to 

demonstrate compliance while burning 

the new fuel(s). 

* * * * * 

(3) If you opt to comply with the 

alternative TSM limit, you must 

establish the maximum TSM fuel input 

(TSMinput) for solid or liquid fuels 

during the initial fuel analysis according 

to the procedures in paragraphs (b)(3)(i) 

through (iii) of this section. 

(i) You must determine the fuel type 

or fuel mixture that you could burn in 

your boiler or process heater that has 

the highest content of TSM. 

(ii) During the fuel analysis for TSM, 

you must determine the fraction of the 

total heat input for each fuel type 

burned (Qi) based on the fuel mixture 

that has the highest content of TSM, and 

the average TSM concentration of each 

fuel type burned (TSMi). 

(iii) You must establish a maximum 

TSM input level using Equation 9 of this 

section. 

Where: 

TSMinput = Maximum amount of TSM 

entering the boiler or process heater 

through fuels burned in units of pounds 

per million Btu. 

TSMi = Arithmetic average concentration of 

TSM in fuel type, i, analyzed according 

to § 63.7521, in units of pounds per 

million Btu. 

Qi = Fraction of total heat input from fuel 

type, i, based on the fuel mixture that 

has the highest content of TSM. If you 

do not burn multiple fuel types during 

the performance testing, it is not 

necessary to determine the value of this 

term. Insert a value of ‘‘1’’ for Qi. 

n = Number of different fuel types burned in 

your boiler or process heater for the 

mixture that has the highest content of 

TSM. 

(4) You must establish parameter 

operating limits according to paragraphs 

(b)(4)(i) through (ix) of this section. As 

indicated in Table 4 to this subpart, you 

are not required to establish and comply 

with the operating parameter limits 

when you are using a CEMS to monitor 

and demonstrate compliance with the 

applicable emission limit for that 

control device parameter. 

(i) For a wet acid gas scrubber, you 

must establish the minimum scrubber 

effluent pH and liquid flow rate as 

defined in § 63.7575, as your operating 

limits during the performance test 

during which you demonstrate 

compliance with your applicable limit. 

If you use a wet scrubber and you 

conduct separate performance tests for 

HCl and mercury emissions, you must 

establish one set of minimum scrubber 

effluent pH, liquid flow rate, and 


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pressure drop operating limits. The 

minimum scrubber effluent pH 

operating limit must be established 

during the HCl performance test. If you 

conduct multiple performance tests, you 

must set the minimum liquid flow rate 

operating limit at the higher of the 

minimum values established during the 

performance tests. 

(ii) For any particulate control device 

(e.g., ESP, particulate wet scrubber, 

fabric filter) for which you use a PM 

CPMS, you must establish your PM 

CPMS operating limit and determine 

compliance with it according to 

paragraphs (b)(4)(ii)(A) through (F) of 

this section. 

(A) Determine your operating limit as 

the average PM CPMS output value 

recorded during the most recent 

performance test run demonstrating 

compliance with the filterable PM 

emission limit or at the PM CPMS 

output value corresponding to 75 

percent of the emission limit if your PM 

performance test demonstrates 

compliance below 75 percent of the 

emission limit. You must verify an 

existing or establish a new operating 

limit after each repeated performance 

test. You must repeat the performance 

test annually and reassess and adjust the 

site-specific operating limit in 

accordance with the results of the 

performance test. 

(1) Your PM CPMS must provide a 4– 

20 milliamp output and the 

establishment of its relationship to 

manual reference method measurements 

must be determined in units of 

milliamps. 

(2) Your PM CPMS operating range 

must be capable of reading PM 

concentrations from zero to a level 

equivalent to at least two times your 

allowable emission limit. If your PM 

CPMS is an auto-ranging instrument 

capable of multiple scales, the primary 

range of the instrument must be capable 

of reading PM concentration from zero 

to a level equivalent to two times your 

allowable emission limit. 

(3) During the initial performance test 

or any such subsequent performance 

test that demonstrates compliance with 

the PM limit, record and average all 

milliamp output values from the PM 

CPMS for the periods corresponding to 

the compliance test runs (e.g., average 

all your PM CPMS output values for 

three corresponding 2-hour Method 5I 

test runs). 

(B) If the average of your three PM 

performance test runs are below 75 

percent of your PM emission limit, you 

must calculate an operating limit by 

establishing a relationship of PM CPMS 

signal to PM concentration using the PM 

CPMS instrument zero, the average PM 

CPMS values corresponding to the three 

compliance test runs, and the average 

PM concentration from the Method 5 or 

performance test with the procedures in 

paragraphs (b)(4)(ii)(B)(1) through (4) of 

this section. 

(1) Determine your instrument zero 

output with one of the following 

procedures: 

(i) Zero point data for in-situ 

instruments should be obtained by 

removing the instrument from the stack 

and monitoring ambient air on a test 

bench. 

(ii) Zero point data for extractive 

instruments should be obtained by 

removing the extractive probe from the 

stack and drawing in clean ambient air. 

(iii) The zero point may also be 

established by performing manual 

reference method measurements when 

the flue gas is free of PM emissions or 

contains very low PM concentrations 

(e.g., when your process is not 

operating, but the fans are operating or 

your source is combusting only natural 

gas) and plotting these with the 

compliance data to find the zero 

intercept. 

(iv) If none of the steps in paragraphs 

(b)(4)(ii)(B)(1)(i) through (iii) of this 

section are possible, you must use a zero 

output value provided by the 

manufacturer. 

(2) Determine your PM CPMS 

instrument average in milliamps, and 

the average of your corresponding three 

PM compliance test runs, using 

equation 10. 

Where: 

X1 = the PM CPMS data points for the three 

runs constituting the performance test, 

Y1 = the PM concentration value for the three 

runs constituting the performance test, 

and 

n = the number of data points. 

(3) With your instrument zero 

expressed in milliamps, your three run 

average PM CPMS milliamp value, and 

your three run average PM 

concentration from your three 

compliance tests, determine a 

relationship of lb/MMBtu per milliamp 

with equation 11. 

Where: 

R = the relative lb/MMBtu per milliamp for 

your PM CPMS, 

Y1 = the three run average lb/MMBtu PM 

concentration, 

X1 = the three run average milliamp output 

from you PM CPMS, and 

z = the milliamp equivalent of your 

instrument zero determined from (B)(i). 

(4) Determine your source specific 30- 

day rolling average operating limit using 

the lb/MMBtu per milliamp value from 

Equation 11 in equation 12, below. This 

sets your operating limit at the PM 

CPMS output value corresponding to 75 

percent of your emission limit. 

Where: 

Ol = the operating limit for your PM CPMS 

on a 30-day rolling average, in 

milliamps. 

L = your source emission limit expressed in 

lb/MMBtu, 

z = your instrument zero in milliamps, 

determined from (B)(i), and 

R = the relative lb/MMBtu per milliamp for 

your PM CPMS, from Equation 11. 

(C) If the average of your three PM 

compliance test runs is at or above 75 

percent of your PM emission limit you 

must determine your 30-day rolling 

average operating limit by averaging the 

PM CPMS milliamp output 

corresponding to your three PM 

performance test runs that demonstrate 

compliance with the emission limit 

using equation 13 and you must submit 

all compliance test and PM CPMS data 

according to the reporting requirements 

in paragraph (b)(4)(ii)(F) of this section. 

Where: 

X1 = the PM CPMS data points for all runs 

i, 

n = the number of data points, and 

Oh = your site specific operating limit, in 

milliamps. 

(D) To determine continuous 

compliance, you must record the PM 


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7176 Federal Register / Vol. 78, No. 21 / Thursday, January 31, 2013 / Rules and Regulations 

CPMS output data for all periods when 

the process is operating and the PM 

CPMS is not out-of-control. You must 

demonstrate continuous compliance by 

using all quality-assured hourly average 

data collected by the PM CPMS for all 

operating hours to calculate the 

arithmetic average operating parameter 

in units of the operating limit 

(milliamps) on a 30-day rolling average 

basis, updated at the end of each new 

operating hour. Use Equation 14 to 

determine the 30-day rolling average. 

Where: 

30-day = 30-day average. 

Hpvi = is the hourly parameter value for hour 

i 

n = is the number of valid hourly parameter 

values collected over the previous 720 

operating hours. 

(E) Use EPA Method 5 of appendix A 

to part 60 of this chapter to determine 

PM emissions. For each performance 

test, conduct three separate runs under 

the conditions that exist when the 

affected source is operating at the 

highest load or capacity level reasonably 

expected to occur. Conduct each test 

run to collect a minimum sample 

volume specified in Tables 1, 2, or 11 

through 13 to this subpart, as 

applicable, for determining compliance 

with a new source limit or an existing 

source limit. Calculate the average of the 

results from three runs to determine 

compliance. You need not determine 

the PM collected in the impingers 

(‘‘back half’’) of the Method 5 

particulate sampling train to 

demonstrate compliance with the PM 

standards of this subpart. This shall not 

preclude the permitting authority from 

requiring a determination of the ‘‘back 

half’’ for other purposes. 

(F) For PM performance test reports 

used to set a PM CPMS operating limit, 

the electronic submission of the test 

report must also include the make and 

model of the PM CPMS instrument, 

serial number of the instrument, 

analytical principle of the instrument 

(e.g. beta attenuation), span of the 

instruments primary analytical range, 

milliamp value equivalent to the 

instrument zero output, technique by 

which this zero value was determined, 

and the average milliamp signals 

corresponding to each PM compliance 

test run. (iii) For a particulate wet 

scrubber, you must establish the 

minimum pressure drop and liquid flow 

rate as defined in § 63.7575, as your 

operating limits during the three-run 

performance test during which you 

demonstrate compliance with your 

applicable limit. If you use a wet 

scrubber and you conduct separate 

performance tests for PM and TSM 

emissions, you must establish one set of 

minimum scrubber liquid flow rate and 

pressure drop operating limits. The 

minimum scrubber effluent pH 

operating limit must be established 

during the HCl performance test. If you 

conduct multiple performance tests, you 

must set the minimum liquid flow rate 

and pressure drop operating limits at 

the higher of the minimum values 

established during the performance 

tests. 

(iii) For an electrostatic precipitator 

(ESP) operated with a wet scrubber, you 

must establish the minimum total 

secondary electric power input, as 

defined in § 63.7575, as your operating 

limit during the three-run performance 

test during which you demonstrate 

compliance with your applicable limit. 

(These operating limits do not apply to 

ESP that are operated as dry controls 

without a wet scrubber.) 

(iv) For a dry scrubber, you must 

establish the minimum sorbent injection 

rate for each sorbent, as defined in 

§ 63.7575, as your operating limit during 

the three-run performance test during 

which you demonstrate compliance 

with your applicable limit. 

(v) For activated carbon injection, you 

must establish the minimum activated 

carbon injection rate, as defined in 

§ 63.7575, as your operating limit during 

the three-run performance test during 

which you demonstrate compliance 

with your applicable limit. 

(vi) The operating limit for boilers or 

process heaters with fabric filters that 

demonstrate continuous compliance 

through bag leak detection systems is 

that a bag leak detection system be 

installed according to the requirements 

in § 63.7525, and that each fabric filter 

must be operated such that the bag leak 

detection system alert is not activated 

more than 5 percent of the operating 

time during a 6-month period. 

(vii) For a minimum oxygen level, if 

you conduct multiple performance tests, 

you must set the minimum oxygen level 

at the lower of the minimum values 

established during the performance 

tests. 

(viii) The operating limit for boilers or 

process heaters that demonstrate 

continuous compliance with the HCl 

emission limit using a SO2 CEMS is to 

install and operate the SO2 according to 

the requirements in § 63.7525(m) 

establish a maximum SO2 emission rate 

equal to the highest hourly average SO2

measurement during the most recent 

three-run performance test for HCl. 

(c) If you elect to demonstrate 

compliance with an applicable emission 

limit through fuel analysis, you must 

conduct fuel analyses according to 

§ 63.7521 and follow the procedures in 

paragraphs (c)(1) through (5) of this 

section. 

* * * * * 

(2) You must determine the 90th 

percentile confidence level fuel 

pollutant concentration of the 

composite samples analyzed for each 

fuel type using the one-sided t-statistic 

test described in Equation 15 of this 

section. 

Where: 

P90 = 90th percentile confidence level 

pollutant concentration, in pounds per 

million Btu. 

Mean = Arithmetic average of the fuel 

pollutant concentration in the fuel 

samples analyzed according to § 63.7521, 

in units of pounds per million Btu. 

SD = Standard deviation of the mean of 

pollutant concentration in the fuel 

samples analyzed according to § 63.7521, 

in units of pounds per million Btu. SD 

is calculated as the sample standard 


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deviation divided by the square root of 

the number of samples. 

t = t distribution critical value for 90th 

percentile (t0.1) probability for the 

appropriate degrees of freedom (number 

of samples minus one) as obtained from 

a t-Distribution Critical Value Table. 

(3) To demonstrate compliance with 

the applicable emission limit for HCl, 

the HCl emission rate that you calculate 

for your boiler or process heater using 

Equation 16 of this section must not 

exceed the applicable emission limit for 

HCl. 

Where: 

HCl = HCl emission rate from the boiler or 

process heater in units of pounds per 

million Btu. 

Ci90 = 90th percentile confidence level 

concentration of chlorine in fuel type, i, 

in units of pounds per million Btu as 

calculated according to Equation 11 of 

this section. 

Qi = Fraction of total heat input from fuel 

type, i, based on the fuel mixture that 

has the highest content of chlorine. If 

you do not burn multiple fuel types, it 

is not necessary to determine the value 

of this term. Insert a value of ‘‘1’’ for Qi. 

n = Number of different fuel types burned in 

your boiler or process heater for the 

mixture that has the highest content of 

chlorine. 

1.028 = Molecular weight ratio of HCl to 

chlorine. 

(4) To demonstrate compliance with 

the applicable emission limit for 

mercury, the mercury emission rate that 

you calculate for your boiler or process 

heater using Equation 17 of this section 

must not exceed the applicable emission 

limit for mercury. 

Where: 

Mercury = Mercury emission rate from the 

boiler or process heater in units of 

pounds per million Btu. 

Hgi90 = 90th percentile confidence level 

concentration of mercury in fuel, i, in 

units of pounds per million Btu as 

calculated according to Equation 11 of 

this section. 

Qi = Fraction of total heat input from fuel 

type, i, based on the fuel mixture that 

has the highest mercury content. If you 

do not burn multiple fuel types, it is not 

necessary to determine the value of this 

term. Insert a value of ‘‘1’’ for Qi. 

n = Number of different fuel types burned in 

your boiler or process heater for the 

mixture that has the highest mercury 

content. 

(5) To demonstrate compliance with 

the applicable emission limit for TSM 

for solid or liquid fuels, the TSM 

emission rate that you calculate for your 

boiler or process heater from solid fuels 

using Equation 18 of this section must 

not exceed the applicable emission limit 

for TSM. 

Where: 

Metals = TSM emission rate from the boiler 

or process heater in units of pounds per 

million Btu. 

TSMi90 = 90th percentile confidence level 

concentration of TSM in fuel, i, in units 

of pounds per million Btu as calculated 

according to Equation 11 of this section. 

Qi = Fraction of total heat input from fuel 

type, i, based on the fuel mixture that 

has the highest TSM content. If you do 

not burn multiple fuel types, it is not 

necessary to determine the value of this 

term. Insert a value of ‘‘1’’ for Qi. 

n = Number of different fuel types burned in 

your boiler or process heater for the 

mixture that has the highest TSM 

content. 

(d) If you own or operate an existing 

unit with a heat input capacity of less 

than 10 million Btu per hour or a unit 

in the unit designed to burn gas 1 

subcategory, you must submit a signed 

statement in the Notification of 

Compliance Status report that indicates 

that you conducted a tune-up of the 

unit. 

(e) You must include with the 

Notification of Compliance Status a 

signed certification that the energy 

assessment was completed according to 

Table 3 to this subpart and is an 

accurate depiction of your facility at the 

time of the assessment. 

* * * * * 

(g) If you elect to demonstrate that a 

gaseous fuel meets the specifications of 

another gas 1 fuel as defined in 

§ 63.7575, you must conduct an initial 

fuel specification analyses according to 

§ 63.7521(f) through (i) and according to 

the frequency listed in § 63.7540(c) and 

maintain records of the results of the 

testing as outlined in § 63.7555(g). For 

samples where the initial mercury 

specification has not been exceeded, 

you will include a signed certification 

with the Notification of Compliance 

Status that the initial fuel specification 

test meets the gas specification outlined 

in the definition of other gas 1 fuels. 

(h) If you own or operate a unit 

subject to emission limits in Tables 1 or 

2 or 11 through 13 to this subpart, you 

must meet the work practice standard 

according to Table 3 of this subpart. 

During startup and shutdown, you must 

only follow the work practice standards 

according to item 5 of Table 3 of this 

subpart. 

(i) If you opt to comply with the 

alternative SO2 CEMS operating limit in 

Tables 4 and 8 to this subpart, you may 

do so only if your affected boiler or 

process heater: 

(1) Has a system using wet scrubber 

or dry sorbent injection and SO2 CEMS 

installed on the unit; and 

(2) At all times, you operate the wet 

scrubber or dry sorbent injection for 

acid gas control on the unit consistent 

with § 63.7500(a)(3); and 

(3) You establish a unit-specific 

maximum SO2 operating limit by 


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collecting the minimum hourly SO2

emission rate on the SO2 CEMS during 

the paired 3-run test for HCl. The 

maximum SO2 operating limit is equal 

to the highest hourly average SO2

concentration measured during the most 

recent HCl performance test. 

■ 19. Section 63.7533 is amended by: 

■ a. Revising the section heading. 

■ b. Revising paragraph (a). 

■ c. Revising paragraphs (b)(1) and (4). 

■ d. Revising paragraphs (c) 

introductory text, (c)(1)(i) and (ii), 

(c)(2)(i), and (c)(3). 

■ e. Revising paragraph (d) through (f). 

■ f. Adding paragraph (g). 

The revisions and addition read as 

follows: 

§ 63.7533 Can I use efficiency credits 

earned from implementation of energy 

conservation measures to comply with this 

subpart? 

(a) If you elect to comply with the 

alternative equivalent output-based 

emission limits, instead of the heat 

input-based limits listed in Table 2 to 

this subpart, and you want to take credit 

for implementing energy conservation 

measures identified in an energy 

assessment, you may demonstrate 

compliance using efficiency credits 

according to the procedures in this 

section. You may use this compliance 

approach for an existing affected boiler 

for demonstrating initial compliance 

according to § 63.7522(e) and for 

demonstrating monthly compliance 

according to § 63.7522(f). Owners or 

operators using this compliance 

approach must establish an emissions 

benchmark, calculate and document the 

efficiency credits, develop an 

Implementation Plan, comply with the 

general reporting requirements, and 

apply the efficiency credit according to 

the procedures in paragraphs (b) 

through (f) of this section. You cannot 

use this compliance approach for a new 

or reconstructed affected boiler. 

Additional guidance from the 

Department of Energy on efficiency 

credits is available at: http:// 

www.epa.gov/ttn/atw/boiler/ 

boilerpg.html. 

(b) * * * 

(1) The benchmark from which 

efficiency credits may be generated shall 

be determined by using the most 

representative, accurate, and reliable 

process available for the source. The 

benchmark shall be established for a 

one-year period before the date that an 

energy demand reduction occurs, unless 

it can be demonstrated that a different 

time period is more representative of 

historical operations. 

* * * * * 

(4) Collect non-energy related facility 

and operational data to normalize, if 

necessary, the benchmark to current 

operations, such as building size, 

operating hours, etc. If possible, use 

actual data that are current and timely 

rather than estimated data. 

(c) Efficiency credits can be generated 

if the energy conservation measures 

were implemented after January 1, 2008 

and if sufficient information is available 

to determine the appropriate value of 

credits. 

(1) The following emission points 

cannot be used to generate efficiency 

credits: 

(i) Energy conservation measures 

implemented on or before January 1, 

2008, unless the level of energy demand 

reduction is increased after January 1, 

2008, in which case credit will be 

allowed only for change in demand 

reduction achieved after January 1, 

2008. 

(ii) Efficiency credits on shut-down 

boilers. Boilers that are shut down 

cannot be used to generate credits 

unless the facility provides 

documentation linking the permanent 

shutdown to energy conservation 

measures identified in the energy 

assessment. In this case, the bench 

established for the affected boiler to 

which the credits from the shutdown 

will be applied must be revised to 

include the benchmark established for 

the shutdown boiler. 

(2) * * * 

(i) Calculate annual credits for all 

energy demand points. Use Equation 19 

to calculate credits. Energy conservation 

measures that meet the criteria of 

paragraph (c)(1) of this section shall not 

be included, except as specified in 

paragraph (c)(1)(i) of this section. 

* * * * * 

(3) Credits are generated by the 

difference between the benchmark that 

is established for each affected boiler, 

and the actual energy demand 

reductions from energy conservation 

measures implemented after January 1, 

2008. Credits shall be calculated using 

Equation 19 of this section as follows: 

(i) The overall equation for calculating 

credits is: 

Where: 

ECredits = Energy Input Savings for all 

energy conservation measures 

implemented for an affected boiler, 

expressed as a decimal fraction of the 

baseline energy input. 

EISiactual = Energy Input Savings for each 

energy conservation measure, i, 

implemented for an affected boiler, 

million Btu per year. 

EIbaseline = Energy Input baseline for the 

affected boiler, million Btu per year. 

n = Number of energy conservation measures 

included in the efficiency credit for the 

affected boiler. 

(ii) [Reserved] 

(d) The owner or operator shall 

develop, and submit for approval upon 

request by the Administrator, an 

Implementation Plan containing all of 

the information required in this 

paragraph for all boilers to be included 

in an efficiency credit approach. The 

Implementation Plan shall identify all 

existing affected boilers to be included 

in applying the efficiency credits. The 

Implementation Plan shall include a 

description of the energy conservation 

measures implemented and the energy 

savings generated from each measure 

and an explanation of the criteria used 

for determining that savings. If 

requested, you must submit the 

implementation plan for efficiency 

credits to the Administrator for review 

and approval no later than 180 days 

before the date on which the facility 

intends to demonstrate compliance 

using the efficiency credit approach. 

(e) The emissions rate as calculated 

using Equation 20 of this section from 

each existing boiler participating in the 

efficiency credit option must be in 

compliance with the limits in Table 2 to 

this subpart at all times the affected unit 

is operating, following the compliance 

date specified in § 63.7495. 

(f) You must use Equation 20 of this 

section to demonstrate initial 

compliance by demonstrating that the 

emissions from the affected boiler 

participating in the efficiency credit 

compliance approach do not exceed the 

emission limits in Table 2 to this 

subpart. 


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Where: 

Eadj = Emission level adjusted by applying 

the efficiency credits earned, lb per 

million Btu steam output (or lb per 

MWh) for the affected boiler. 

Em = Emissions measured during the 

performance test, lb per million Btu 

steam output (or lb per MWh) for the 

affected boiler. 

ECredits = Efficiency credits from Equation 

19 for the affected boiler. 

(g) As part of each compliance report 

submitted as required under § 63.7550, 

you must include documentation that 

the energy conservation measures 

implemented continue to generate the 

credit for use in demonstrating 

compliance with the emission limits. 

■ 20. Section 63.7535 is amended by 

revising the section heading and 

paragraphs (b), (c), and (d) to read as 

follows: 

§ 63.7535 Is there a minimum amount of 

monitoring data I must obtain? 

* * * * * 

(b) You must operate the monitoring 

system and collect data at all required 

intervals at all times that each boiler or 

process heater is operating and 

compliance is required, except for 

periods of monitoring system 

malfunctions or out of control periods 

(see § 63.8(c)(7) of this part), and 

required monitoring system quality 

assurance or control activities, 

including, as applicable, calibration 

checks, required zero and span 

adjustments, and scheduled CMS 

maintenance as defined in your sitespecific monitoring plan. A monitoring 

system malfunction is any sudden, 

infrequent, not reasonably preventable 

failure of the monitoring system to 

provide valid data. Monitoring system 

failures that are caused in part by poor 

maintenance or careless operation are 

not malfunctions. You are required to 

complete monitoring system repairs in 

response to monitoring system 

malfunctions or out-of-control periods 

and to return the monitoring system to 

operation as expeditiously as 

practicable. 

(c) You may not use data recorded 

during monitoring system malfunctions 

or out-of-control periods, repairs 

associated with monitoring system 

malfunctions or out-of-control periods, 

or required monitoring system quality 

assurance or control activities in data 

averages and calculations used to report 

emissions or operating levels. You must 

record and make available upon request 

results of CMS performance audits and 

dates and duration of periods when the 

CMS is out of control to completion of 

the corrective actions necessary to 

return the CMS to operation consistent 

with your site-specific monitoring plan. 

You must use all the data collected 

during all other periods in assessing 

compliance and the operation of the 

control device and associated control 

system. 

(d) Except for periods of monitoring 

system malfunctions, repairs associated 

with monitoring system malfunctions, 

and required monitoring system quality 

assurance or quality control activities 

(including, as applicable, system 

accuracy audits, calibration checks, and 

required zero and span adjustments), 

failure to collect required data is a 

deviation of the monitoring 

requirements. In calculating monitoring 

results, do not use any data collected 

during periods when the monitoring 

system is out of control as specified in 

your site-specific monitoring plan, 

while conducting repairs associated 

with periods when the monitoring 

system is out of control, or while 

conducting required monitoring system 

quality assurance or quality control 

activities. You must calculate 

monitoring results using all other 

monitoring data collected while the 

process is operating. You must report all 

periods when the monitoring system is 

out of control in your annual report. 

■ 21. Section 63.7540 is revised to read 

as follows: 

§ 63.7540 How do I demonstrate 

continuous compliance with the emission 

limitations, fuel specifications and work 

practice standards? 

(a) You must demonstrate continuous 

compliance with each emission limit in 

Tables 1 and 2 or 11 through 13 to this 

subpart, the work practice standards in 

Table 3 to this subpart, and the 

operating limits in Table 4 to this 

subpart that applies to you according to 

the methods specified in Table 8 to this 

subpart and paragraphs (a)(1) through 

(19) of this section. 

(1) Following the date on which the 

initial compliance demonstration is 

completed or is required to be 

completed under §§ 63.7 and 63.7510, 

whichever date comes first, operation 

above the established maximum or 

below the established minimum 

operating limits shall constitute a 

deviation of established operating limits 

listed in Table 4 of this subpart except 

during performance tests conducted to 

determine compliance with the 

emission limits or to establish new 

operating limits. Operating limits must 

be confirmed or reestablished during 

performance tests. 

(2) As specified in § 63.7550(c), you 

must keep records of the type and 

amount of all fuels burned in each 

boiler or process heater during the 

reporting period to demonstrate that all 

fuel types and mixtures of fuels burned 

would result in either of the following: 

(i) Lower emissions of HCl, mercury, 

and TSM than the applicable emission 

limit for each pollutant, if you 

demonstrate compliance through fuel 

analysis. 

(ii) Lower fuel input of chlorine, 

mercury, and TSM than the maximum 

values calculated during the last 

performance test, if you demonstrate 

compliance through performance 

testing. 

(3) If you demonstrate compliance 

with an applicable HCl emission limit 

through fuel analysis for a solid or 

liquid fuel and you plan to burn a new 

type of solid or liquid fuel, you must 

recalculate the HCl emission rate using 

Equation 12 of § 63.7530 according to 

paragraphs (a)(3)(i) through (iii) of this 

section. You are not required to conduct 

fuel analyses for the fuels described in 

§ 63.7510(a)(2)(i) through (iii). You may 

exclude the fuels described in 

§ 63.7510(a)(2)(i) through (iii) when 

recalculating the HCl emission rate. 

(i) You must determine the chlorine 

concentration for any new fuel type in 

units of pounds per million Btu, based 

on supplier data or your own fuel 

analysis, according to the provisions in 

your site-specific fuel analysis plan 

developed according to § 63.7521(b). 

(ii) You must determine the new 

mixture of fuels that will have the 

highest content of chlorine. 

(iii) Recalculate the HCl emission rate 

from your boiler or process heater under 

these new conditions using Equation 12 

of § 63.7530. The recalculated HCl 

emission rate must be less than the 

applicable emission limit. 

(4) If you demonstrate compliance 

with an applicable HCl emission limit 

through performance testing and you 

plan to burn a new type of fuel or a new 

mixture of fuels, you must recalculate 

the maximum chlorine input using 

Equation 7 of § 63.7530. If the results of 

recalculating the maximum chlorine 

input using Equation 7 of § 63.7530 are 

greater than the maximum chlorine 

input level established during the 

previous performance test, then you 

must conduct a new performance test 

within 60 days of burning the new fuel 

type or fuel mixture according to the 


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procedures in § 63.7520 to demonstrate 

that the HCl emissions do not exceed 

the emission limit. You must also 

establish new operating limits based on 

this performance test according to the 

procedures in § 63.7530(b). In 

recalculating the maximum chlorine 

input and establishing the new 

operating limits, you are not required to 

conduct fuel analyses for and include 

the fuels described in § 63.7510(a)(2)(i) 

through (iii). 

(5) If you demonstrate compliance 

with an applicable mercury emission 

limit through fuel analysis, and you 

plan to burn a new type of fuel, you 

must recalculate the mercury emission 

rate using Equation 13 of § 63.7530 

according to the procedures specified in 

paragraphs (a)(5)(i) through (iii) of this 

section. You are not required to conduct 

fuel analyses for the fuels described in 

§ 63.7510(a)(2)(i) through (iii). You may 

exclude the fuels described in 

§ 63.7510(a)(2)(i) through (iii) when 

recalculating the mercury emission rate. 

(i) You must determine the mercury 

concentration for any new fuel type in 

units of pounds per million Btu, based 

on supplier data or your own fuel 

analysis, according to the provisions in 

your site-specific fuel analysis plan 

developed according to § 63.7521(b). 

(ii) You must determine the new 

mixture of fuels that will have the 

highest content of mercury. 

(iii) Recalculate the mercury emission 

rate from your boiler or process heater 

under these new conditions using 

Equation 13 of § 63.7530. The 

recalculated mercury emission rate must 

be less than the applicable emission 

limit. 

(6) If you demonstrate compliance 

with an applicable mercury emission 

limit through performance testing, and 

you plan to burn a new type of fuel or 

a new mixture of fuels, you must 

recalculate the maximum mercury input 

using Equation 8 of § 63.7530. If the 

results of recalculating the maximum 

mercury input using Equation 8 of 

§ 63.7530 are higher than the maximum 

mercury input level established during 

the previous performance test, then you 

must conduct a new performance test 

within 60 days of burning the new fuel 

type or fuel mixture according to the 

procedures in § 63.7520 to demonstrate 

that the mercury emissions do not 

exceed the emission limit. You must 

also establish new operating limits 

based on this performance test 

according to the procedures in 

§ 63.7530(b). You are not required to 

conduct fuel analyses for the fuels 

described in § 63.7510(a)(2)(i) through 

(iii). You may exclude the fuels 

described in § 63.7510(a)(2)(i) through 

(iii) when recalculating the mercury 

emission rate. 

(7) If your unit is controlled with a 

fabric filter, and you demonstrate 

continuous compliance using a bag leak 

detection system, you must initiate 

corrective action within 1 hour of a bag 

leak detection system alert and 

complete corrective actions as soon as 

practical, and operate and maintain the 

fabric filter system such that the periods 

which would cause an alert are no more 

than 5 percent of the operating time 

during a 6-month period. You must also 

keep records of the date, time, and 

duration of each alert, the time 

corrective action was initiated and 

completed, and a brief description of the 

cause of the alert and the corrective 

action taken. You must also record the 

percent of the operating time during 

each 6-month period that the conditions 

exist for an alert. In calculating this 

operating time percentage, if inspection 

of the fabric filter demonstrates that no 

corrective action is required, no alert 

time is counted. If corrective action is 

required, each alert shall be counted as 

a minimum of 1 hour. If you take longer 

than 1 hour to initiate corrective action, 

the alert time shall be counted as the 

actual amount of time taken to initiate 

corrective action. 

(8) To demonstrate compliance with 

the applicable alternative CO CEMS 

emission limit listed in Tables 1, 2, or 

11 through 13 to this subpart, you must 

meet the requirements in paragraphs 

(a)(8)(i) through (iv) of this section. 

(i) Continuously monitor CO 

according to §§ 63.7525(a) and 63.7535. 

(ii) Maintain a CO emission level 

below or at your applicable alternative 

CO CEMS-based standard in Tables 1 or 

2 or 11 through 13 to this subpart at all 

times the affected unit is operating. 

(iii) Keep records of CO levels 

according to § 63.7555(b). 

(iv) You must record and make 

available upon request results of CO 

CEMS performance audits, dates and 

duration of periods when the CO CEMS 

is out of control to completion of the 

corrective actions necessary to return 

the CO CEMS to operation consistent 

with your site-specific monitoring plan. 

(9) The owner or operator of a boiler 

or process heater using a PM CPMS or 

a PM CEMS to meet requirements of this 

subpart shall install, certify, operate, 

and maintain the PM CPMS or PM 

CEMS in accordance with your sitespecific monitoring plan as required in 

§ 63.7505(d). 

(10) If your boiler or process heater 

has a heat input capacity of 10 million 

Btu per hour or greater, you must 

conduct an annual tune-up of the boiler 

or process heater to demonstrate 

continuous compliance as specified in 

paragraphs (a)(10)(i) through (vi) of this 

section. This frequency does not apply 

to limited-use boilers and process 

heaters, as defined in § 63.7575, or units 

with continuous oxygen trim systems 

that maintain an optimum air to fuel 

ratio. 

(i) As applicable, inspect the burner, 

and clean or replace any components of 

the burner as necessary (you may delay 

the burner inspection until the next 

scheduled unit shutdown). Units that 

produce electricity for sale may delay 

the burner inspection until the first 

outage, not to exceed 36 months from 

the previous inspection. At units where 

entry into a piece of process equipment 

or into a storage vessel is required to 

complete the tune-up inspections, 

inspections are required only during 

planned entries into the storage vessel 

or process equipment; 

(ii) Inspect the flame pattern, as 

applicable, and adjust the burner as 

necessary to optimize the flame pattern. 

The adjustment should be consistent 

with the manufacturer’s specifications, 

if available; 

(iii) Inspect the system controlling the 

air-to-fuel ratio, as applicable, and 

ensure that it is correctly calibrated and 

functioning properly (you may delay the 

inspection until the next scheduled unit 

shutdown). Units that produce 

electricity for sale may delay the 

inspection until the first outage, not to 

exceed 36 months from the previous 

inspection; 

(iv) Optimize total emissions of CO. 

This optimization should be consistent 

with the manufacturer’s specifications, 

if available, and with any NOX

requirement to which the unit is subject; 

(v) Measure the concentrations in the 

effluent stream of CO in parts per 

million, by volume, and oxygen in 

volume percent, before and after the 

adjustments are made (measurements 

may be either on a dry or wet basis, as 

long as it is the same basis before and 

after the adjustments are made). 

Measurements may be taken using a 

portable CO analyzer; and 

(vi) Maintain on-site and submit, if 

requested by the Administrator, an 

annual report containing the 

information in paragraphs (a)(10)(vi)(A) 

through (C) of this section, 

(A) The concentrations of CO in the 

effluent stream in parts per million by 

volume, and oxygen in volume percent, 

measured at high fire or typical 

operating load, before and after the 

tune-up of the boiler or process heater; 

(B) A description of any corrective 

actions taken as a part of the tune-up; 

and 


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Federal Register / Vol. 78, No. 21 / Thursday, January 31, 2013 / Rules and Regulations 7181 

(C) The type and amount of fuel used 

over the 12 months prior to the tune-up, 

but only if the unit was physically and 

legally capable of using more than one 

type of fuel during that period. Units 

sharing a fuel meter may estimate the 

fuel used by each unit. 

(11) If your boiler or process heater 

has a heat input capacity of less than 10 

million Btu per hour (except as 

specified in paragraph (a)(12) of this 

section), you must conduct a biennial 

tune-up of the boiler or process heater 

as specified in paragraphs (a)(10)(i) 

through (vi) of this section to 

demonstrate continuous compliance. 

(12) If your boiler or process heater 

has a continuous oxygen trim system 

that maintains an optimum air to fuel 

ratio, or a heat input capacity of less 

than or equal to 5 million Btu per hour 

and the unit is in the units designed to 

burn gas 1; units designed to burn gas 

2 (other); or units designed to burn light 

liquid subcategories, or meets the 

definition of limited-use boiler or 

process heater in § 63.7575, you must 

conduct a tune-up of the boiler or 

process heater every 5 years as specified 

in paragraphs (a)(10)(i) through (vi) of 

this section to demonstrate continuous 

compliance. You may delay the burner 

inspection specified in paragraph 

(a)(10)(i) of this section until the next 

scheduled or unscheduled unit 

shutdown, but you must inspect each 

burner at least once every 72 months. 

(13) If the unit is not operating on the 

required date for a tune-up, the tune-up 

must be conducted within 30 calendar 

days of startup. 

(14) If you are using a CEMS 

measuring mercury emissions to meet 

requirements of this subpart you must 

install, certify, operate, and maintain 

the mercury CEMS as specified in 

paragraphs (a)(14)(i) and (ii) of this 

section. 

(i) Operate the mercury CEMS in 

accordance with performance 

specification 12A of 40 CFR part 60, 

appendix B or operate a sorbent trap 

based integrated monitor in accordance 

with performance specification 12B of 

40 CFR part 60, appendix B. The 

duration of the performance test must be 

the maximum of 30 unit operating days 

or 720 hours. For each day in which the 

unit operates, you must obtain hourly 

mercury concentration data, and stack 

gas volumetric flow rate data. 

(ii) If you are using a mercury CEMS, 

you must install, operate, calibrate, and 

maintain an instrument for 

continuously measuring and recording 

the mercury mass emissions rate to the 

atmosphere according to the 

requirements of performance 

specifications 6 and 12A of 40 CFR part 

60, appendix B, and quality assurance 

procedure 6 of 40 CFR part 60, appendix 

F. 

(15) If you are using a CEMS to 

measure HCl emissions to meet 

requirements of this subpart, you must 

install, certify, operate, and maintain 

the HCl CEMS as specified in 

paragraphs (a)(15)(i) and (ii) of this 

section. This option for an affected unit 

takes effect on the date a final 

performance specification for an HCl 

CEMS is published in the Federal 

Register or the date of approval of a sitespecific monitoring plan. 

(i) Operate the continuous emissions 

monitoring system in accordance with 

the applicable performance 

specification in 40 CFR part 60, 

appendix B. The duration of the 

performance test must be the maximum 

of 30 unit operating days or 720 hours. 

For each day in which the unit operates, 

you must obtain hourly HCl 

concentration data, and stack gas 

volumetric flow rate data. 

(ii) If you are using a HCl CEMS, you 

must install, operate, calibrate, and 

maintain an instrument for 

continuously measuring and recording 

the HCl mass emissions rate to the 

atmosphere according to the 

requirements of the applicable 

performance specification of 40 CFR 

part 60, appendix B, and the quality 

assurance procedures of 40 CFR part 60, 

appendix F. 

(16) If you demonstrate compliance 

with an applicable TSM emission limit 

through performance testing, and you 

plan to burn a new type of fuel or a new 

mixture of fuels, you must recalculate 

the maximum TSM input using 

Equation 9 of § 63.7530. If the results of 

recalculating the maximum TSM input 

using Equation 9 of § 63.7530 are higher 

than the maximum total selected input 

level established during the previous 

performance test, then you must 

conduct a new performance test within 

60 days of burning the new fuel type or 

fuel mixture according to the 

procedures in § 63.7520 to demonstrate 

that the TSM emissions do not exceed 

the emission limit. You must also 

establish new operating limits based on 

this performance test according to the 

procedures in § 63.7530(b). You are not 

required to conduct fuel analyses for the 

fuels described in § 63.7510(a)(2)(i) 

through (iii). You may exclude the fuels 

described in § 63.7510(a)(2)(i) through 

(iii) when recalculating the TSM 

emission rate. 

(17) If you demonstrate compliance 

with an applicable TSM emission limit 

through fuel analysis for solid or liquid 

fuels, and you plan to burn a new type 

of fuel, you must recalculate the TSM 

emission rate using Equation 14 of 

§ 63.7530 according to the procedures 

specified in paragraphs (a)(5)(i) through 

(iii) of this section. You are not required 

to conduct fuel analyses for the fuels 

described in § 63.7510(a)(2)(i) through 

(iii). You may exclude the fuels 

described in § 63.7510(a)(2)(i) through 

(iii) when recalculating the TSM 

emission rate. 

(i) You must determine the TSM 

concentration for any new fuel type in 

units of pounds per million Btu, based 

on supplier data or your own fuel 

analysis, according to the provisions in 

your site-specific fuel analysis plan 

developed according to § 63.7521(b). 

(ii) You must determine the new 

mixture of fuels that will have the 

highest content of TSM. 

(iii) Recalculate the TSM emission 

rate from your boiler or process heater 

under these new conditions using 

Equation 14 of § 63.7530. The 

recalculated TSM emission rate must be 

less than the applicable emission limit. 

(18) If you demonstrate continuous 

PM emissions compliance with a PM 

CPMS you will use a PM CPMS to 

establish a site-specific operating limit 

corresponding to the results of the 

performance test demonstrating 

compliance with the PM limit. You will 

conduct your performance test using the 

test method criteria in Table 5 of this 

subpart. You will use the PM CPMS to 

demonstrate continuous compliance 

with this operating limit. You must 

repeat the performance test annually 

and reassess and adjust the site-specific 

operating limit in accordance with the 

results of the performance test. 

(i) To determine continuous 

compliance, you must record the PM 

CPMS output data for all periods when 

the process is operating and the PM 

CPMS is not out-of-control. You must 

demonstrate continuous compliance by 

using all quality-assured hourly average 

data collected by the PM CPMS for all 

operating hours to calculate the 

arithmetic average operating parameter 

in units of the operating limit 

(milliamps) on a 30-day rolling average 

basis, updated at the end of each new 

boiler or process heater operating hour. 

(ii) For any deviation of the 30-day 

rolling PM CPMS average value from the 

established operating parameter limit, 

you must: 

(A) Within 48 hours of the deviation, 

visually inspect the air pollution control 

device (APCD); 

(B) If inspection of the APCD 

identifies the cause of the deviation, 

take corrective action as soon as 

possible and return the PM CPMS 

measurement to within the established 

value; and 


tkelley on DSK3SPTVN1PROD with 
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(C) Within 30 days of the deviation or 

at the time of the annual compliance 

test, whichever comes first, conduct a 

PM emissions compliance test to 

determine compliance with the PM 

emissions limit and to verify or reestablish the CPMS operating limit. You 

are not required to conduct additional 

testing for any deviations that occur 

between the time of the original 

deviation and the PM emissions 

compliance test required under this 

paragraph. 

(iii) PM CPMS deviations from the 

operating limit leading to more than 

four required performance tests in a 12- 

month operating period constitute a 

separate violation of this subpart. 

(19) If you choose to comply with the 

PM filterable emissions limit by using 

PM CEMS you must install, certify, 

operate, and maintain a PM CEMS and 

record the output of the PM CEMS as 

specified in paragraphs (a)(19)(i) 

through (vii) of this section. The 

compliance limit will be expressed as a 

30-day rolling average of the numerical 

emissions limit value applicable for 

your unit in Tables 1 or 2 or 11 through 

13 of this subpart. 

(i) Install and certify your PM CEMS 

according to the procedures and 

requirements in Performance 

Specification 11—Specifications and 

Test Procedures for Particulate Matter 

Continuous Emission Monitoring 

Systems at Stationary Sources in 

Appendix B to part 60 of this chapter, 

using test criteria outlined in Table V of 

this rule. The reportable measurement 

output from the PM CEMS must be 

expressed in units of the applicable 

emissions limit (e.g., lb/MMBtu, lb/ 

MWh). 

(ii) Operate and maintain your PM 

CEMS according to the procedures and 

requirements in Procedure 2— Quality 

Assurance Requirements for Particulate 

Matter Continuous Emission Monitoring 

Systems at Stationary Sources in 

Appendix F to part 60 of this chapter. 

(A) You must conduct the relative 

response audit (RRA) for your PM CEMS 

at least once annually. 

(B) You must conduct the relative 

correlation audit (RCA) for your PM 

CEMS at least once every 3 years. 

(iii) Collect PM CEMS hourly average 

output data for all boiler operating 

hours except as indicated in paragraph 

(i) of this section. 

(iv) Calculate the arithmetic 30-day 

rolling average of all of the hourly 

average PM CEMS output data collected 

during all nonexempt boiler or process 

heater operating hours. 

(v) You must collect data using the 

PM CEMS at all times the unit is 

operating and at the intervals specified 

this paragraph (a), except for periods of 

monitoring system malfunctions, repairs 

associated with monitoring system 

malfunctions, and required monitoring 

system quality assurance or quality 

control activities. 

(vi) You must use all the data 

collected during all boiler or process 

heater operating hours in assessing the 

compliance with your operating limit 

except: 

(A) Any data collected during 

monitoring system malfunctions, repairs 

associated with monitoring system 

malfunctions, or required monitoring 

system quality assurance or control 

activities conducted during monitoring 

system malfunctions in calculations and 

report any such periods in your annual 

deviation report; 

(B) Any data collected during periods 

when the monitoring system is out of 

control as specified in your site-specific 

monitoring plan, repairs associated with 

periods when the monitoring system is 

out of control, or required monitoring 

system quality assurance or control 

activities conducted during out of 

control periods in calculations used to 

report emissions or operating levels and 

report any such periods in your annual 

deviation report; 

(C) Any data recorded during periods 

of startup or shutdown. 

(vii) You must record and make 

available upon request results of PM 

CEMS system performance audits, dates 

and duration of periods when the PM 

CEMS is out of control to completion of 

the corrective actions necessary to 

return the PM CEMS to operation 

consistent with your site-specific 

monitoring plan. 

(b) You must report each instance in 

which you did not meet each emission 

limit and operating limit in Tables 1 

through 4 or 11 through 13 to this 

subpart that apply to you. These 

instances are deviations from the 

emission limits or operating limits, 

respectively, in this subpart. These 

deviations must be reported according 

to the requirements in § 63.7550. 

(c) If you elected to demonstrate that 

the unit meets the specification for 

mercury for the unit designed to burn 

gas 1 subcategory, you must follow the 

sampling frequency specified in 

paragraphs (c)(1) through (4) of this 

section and conduct this sampling 

according to the procedures in 

§ 63.7521(f) through (i). 

(1) If the initial mercury constituents 

in the gaseous fuels are measured to be 

equal to or less than half of the mercury 

specification as defined in § 63.7575, 

you do not need to conduct further 

sampling. 

(2) If the initial mercury constituents 

are greater than half but equal to or less 

than 75 percent of the mercury 

specification as defined in § 63.7575, 

you will conduct semi-annual sampling. 

If 6 consecutive semi-annual fuel 

analyses demonstrate 50 percent or less 

of the mercury specification, you do not 

need to conduct further sampling. If any 

semi-annual sample exceeds 75 percent 

of the mercury specification, you must 

return to monthly sampling for that fuel, 

until 12 months of fuel analyses again 

are less than 75 percent of the 

compliance level. 

(3) If the initial mercury constituents 

are greater than 75 percent of the 

mercury specification as defined in 

§ 63.7575, you will conduct monthly 

sampling. If 12 consecutive monthly 

fuel analyses demonstrate 75 percent or 

less of the mercury specification, you 

may decrease the fuel analysis 

frequency to semi-annual for that fuel. 

(4) If the initial sample exceeds the 

mercury specification as defined in 

§ 63.7575, each affected boiler or 

process heater combusting this fuel is 

not part of the unit designed to burn gas 

1 subcategory and must be in 

compliance with the emission and 

operating limits for the appropriate 

subcategory. You may elect to conduct 

additional monthly sampling while 

complying with these emissions and 

operating limits to demonstrate that the 

fuel qualifies as another gas 1 fuel. If 12 

consecutive monthly fuel analyses 

samples are at or below the mercury 

specification as defined in § 63.7575, 

each affected boiler or process heater 

combusting the fuel can elect to switch 

back into the unit designed to burn gas 

1 subcategory until the mercury 

specification is exceeded. 

(d) For startup and shutdown, you 

must meet the work practice standards 

according to item 5 of Table 3 of this 

subpart. 

■ 22. Section 63.7541 is amended by 

revising paragraphs (a)(3) and (4) to read 

as follows: 

§ 63.7541 How do I demonstrate 

continuous compliance under the 

emissions averaging provision? 

* * * * * 

(a) * * * 

(3) For each existing unit participating 

in the emissions averaging option that is 

equipped with a wet scrubber, maintain 

the 30-day rolling average parameter 

values at or above the operating limits 

established during the most recent 

performance test. 

(4) For each existing unit participating 

in the emissions averaging option that 

has an approved alternative operating 

parameter, maintain the 30-day rolling 


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Federal Register / Vol. 78, No. 21 / Thursday, January 31, 2013 / Rules and Regulations 7183 

average parameter values consistent 

with the approved monitoring plan. 

* * * * * 

■ 23. Section 63.7545 is amended by: 

■ a. Revising paragraphs (a) through (c). 

■ b. Revising paragraphs (e) 

introductory text, (e)(1), (e)(2), (e)(3), 

(e)(4), (e)(5) introductory text, and 

(e)(5)(i). 

■ c. Adding paragraph (e)(5)(ii). 

■ d. Revising paragraphs (e)(8)(i) and 

(iii). 

■ e. Revising paragraph (f) introductory 

text. 

■ f. Revising paragraphs (g)(1) and (2). 

■ g. Revising paragraphs (h) 

introductory text and (h)(1) and (3). 

■ h. Removing paragraph (h)(4). 

The revisions and addition read as 

follows: 

§ 63.7545 What notifications must I submit 

and when? 

(a) You must submit to the 

Administrator all of the notifications in 

§§ 63.7(b) and (c), 63.8(e), (f)(4) and (6), 

and 63.9(b) through (h) that apply to 

you by the dates specified. 

(b) As specified in § 63.9(b)(2), if you 

startup your affected source before 

January 31, 2013, you must submit an 

Initial Notification not later than 120 

days after January 31, 2013. 

(c) As specified in § 63.9(b)(4) and (5), 

if you startup your new or reconstructed 

affected source on or after January 31, 

2013, you must submit an Initial 

Notification not later than 15 days after 

the actual date of startup of the affected 

source. 

* * * * * 

(e) If you are required to conduct an 

initial compliance demonstration as 

specified in § 63.7530, you must submit 

a Notification of Compliance Status 

according to § 63.9(h)(2)(ii). For the 

initial compliance demonstration for 

each boiler or process heater, you must 

submit the Notification of Compliance 

Status, including all performance test 

results and fuel analyses, before the 

close of business on the 60th day 

following the completion of all 

performance test and/or other initial 

compliance demonstrations for all boiler 

or process heaters at the facility 

according to § 63.10(d)(2). The 

Notification of Compliance Status report 

must contain all the information 

specified in paragraphs (e)(1) through 

(8), as applicable. If you are not required 

to conduct an initial compliance 

demonstration as specified in 

§ 63.7530(a), the Notification of 

Compliance Status must only contain 

the information specified in paragraphs 

(e)(1) and (8). 

(1) A description of the affected 

unit(s) including identification of which 

subcategories the unit is in, the design 

heat input capacity of the unit, a 

description of the add-on controls used 

on the unit to comply with this subpart, 

description of the fuel(s) burned, 

including whether the fuel(s) were a 

secondary material determined by you 

or the EPA through a petition process to 

be a non-waste under § 241.3 of this 

chapter, whether the fuel(s) were a 

secondary material processed from 

discarded non-hazardous secondary 

materials within the meaning of § 241.3 

of this chapter, and justification for the 

selection of fuel(s) burned during the 

compliance demonstration. 

(2) Summary of the results of all 

performance tests and fuel analyses, and 

calculations conducted to demonstrate 

initial compliance including all 

established operating limits, and 

including: 

(i) Identification of whether you are 

complying with the PM emission limit 

or the alternative TSM emission limit. 

(ii) Identification of whether you are 

complying with the output-based 

emission limits or the heat input-based 

(i.e., lb/MMBtu or ppm) emission limits, 

(3) A summary of the maximum CO 

emission levels recorded during the 

performance test to show that you have 

met any applicable emission standard in 

Tables 1, 2, or 11 through 13 to this 

subpart, if you are not using a CO CEMS 

to demonstrate compliance. 

(4) Identification of whether you plan 

to demonstrate compliance with each 

applicable emission limit through 

performance testing, a CEMS, or fuel 

analysis. 

(5) Identification of whether you plan 

to demonstrate compliance by emissions 

averaging and identification of whether 

you plan to demonstrate compliance by 

using efficiency credits through energy 

conservation: 

(i) If you plan to demonstrate 

compliance by emission averaging, 

report the emission level that was being 

achieved or the control technology 

employed on January 31, 2013. 

(ii) [Reserved] 

* * * * * 

(8) * * * 

(i) ‘‘This facility complies with the 

required initial tune-up according to the 

procedures in § 63.7540(a)(10)(i) 

through (vi).’’ 

* * * * * 

(iii) Except for units that burn only 

natural gas, refinery gas, or other gas 1 

fuel, or units that qualify for a statutory 

exemption as provided in section 

129(g)(1) of the Clean Air Act, include 

the following: ‘‘No secondary materials 

that are solid waste were combusted in 

any affected unit.’’ 

(f) If you operate a unit designed to 

burn natural gas, refinery gas, or other 

gas 1 fuels that is subject to this subpart, 

and you intend to use a fuel other than 

natural gas, refinery gas, gaseous fuel 

subject to another subpart of this part, 

part 60, 61, or 65, or other gas 1 fuel to 

fire the affected unit during a period of 

natural gas curtailment or supply 

interruption, as defined in § 63.7575, 

you must submit a notification of 

alternative fuel use within 48 hours of 

the declaration of each period of natural 

gas curtailment or supply interruption, 

as defined in § 63.7575. The notification 

must include the information specified 

in paragraphs (f)(1) through (5) of this 

section. 

* * * * * 

(g) * * * 

(1) The name of the owner or operator 

of the affected source, as defined in 

§ 63.7490, the location of the source, the 

boiler(s) or process heater(s) that will 

commence burning solid waste, and the 

date of the notice. 

(2) The currently applicable 

subcategories under this subpart. 

* * * * * 

(h) If you have switched fuels or made 

a physical change to the boiler and the 

fuel switch or physical change resulted 

in the applicability of a different 

subcategory, you must provide notice of 

the date upon which you switched fuels 

or made the physical change within 30 

days of the switch/change. The 

notification must identify: 

(1) The name of the owner or operator 

of the affected source, as defined in 

§ 63.7490, the location of the source, the 

boiler(s) and process heater(s) that have 

switched fuels, were physically 

changed, and the date of the notice. 

* * * * * 

(3) The date upon which the fuel 

switch or physical change occurred. 

■ 24. Section 63.7550 is revised to read 

as follows: 

§ 63.7550 What reports must I submit and 

when? 

(a) You must submit each report in 

Table 9 to this subpart that applies to 

you. 

(b) Unless the EPA Administrator has 

approved a different schedule for 

submission of reports under § 63.10(a), 

you must submit each report, according 

to paragraph (h) of this section, by the 

date in Table 9 to this subpart and 

according to the requirements in 

paragraphs (b)(1) through (4) of this 

section. For units that are subject only 

to a requirement to conduct an annual, 

biennial, or 5-year tune-up according to 

§ 63.7540(a)(10), (11), or (12), 

respectively, and not subject to emission 


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7184 Federal Register / Vol. 78, No. 21 / Thursday, January 31, 2013 / Rules and Regulations 

limits or operating limits, you may 

submit only an annual, biennial, or 5- 

year compliance report, as applicable, as 

specified in paragraphs (b)(1) through 

(4) of this section, instead of a semiannual compliance report. 

(1) The first compliance report must 

cover the period beginning on the 

compliance date that is specified for 

each boiler or process heater in 

§ 63.7495 and ending on July 31 or 

January 31, whichever date is the first 

date that occurs at least 180 days (or 1, 

2, or 5 years, as applicable, if submitting 

an annual, biennial, or 5-year 

compliance report) after the compliance 

date that is specified for your source in 

§ 63.7495. 

(2) The first compliance report must 

be postmarked or submitted no later 

than July 31 or January 31, whichever 

date is the first date following the end 

of the first calendar half after the 

compliance date that is specified for 

each boiler or process heater in 

§ 63.7495. The first annual, biennial, or 

5-year compliance report must be 

postmarked or submitted no later than 

January 31. 

(3) Each subsequent compliance 

report must cover the semiannual 

reporting period from January 1 through 

June 30 or the semiannual reporting 

period from July 1 through December 

31. Annual, biennial, and 5-year 

compliance reports must cover the 

applicable 1-, 2-, or 5-year periods from 

January 1 to December 31. 

(4) Each subsequent compliance 

report must be postmarked or submitted 

no later than July 31 or January 31, 

whichever date is the first date 

following the end of the semiannual 

reporting period. Annual, biennial, and 

5-year compliance reports must be 

postmarked or submitted no later than 

January 31. 

(c) A compliance report must contain 

the following information depending on 

how the facility chooses to comply with 

the limits set in this rule. 

(1) If the facility is subject to a the 

requirements of a tune up they must 

submit a compliance report with the 

information in paragraphs (c)(5)(i) 

through (iv) and (xiv) of this section. 

(2) If a facility is complying with the 

fuel analysis they must submit a 

compliance report with the information 

in paragraphs (c)(5)(i) through (iv), (vi), 

(x), (xi), (xiii), (xv) and paragraph (d) of 

this section. 

(3) If a facility is complying with the 

applicable emissions limit with 

performance testing they must submit a 

compliance report with the information 

in (c)(5)(i) through (iv), (vi), (vii), (ix), 

(xi), (xiii), (xv) and paragraph (d) of this 

section. 

(4) If a facility is complying with an 

emissions limit using a CMS the 

compliance report must contain the 

information required in paragraphs 

(c)(5)(i) through (vi), (xi), (xiii), (xv) 

through (xvii), and paragraph (e) of this 

section. 

(5)(i) Company and Facility name and 

address. 

(ii) Process unit information, 

emissions limitations, and operating 

parameter limitations. 

(iii) Date of report and beginning and 

ending dates of the reporting period. 

(iv) The total operating time during 

the reporting period. 

(v) If you use a CMS, including CEMS, 

COMS, or CPMS, you must include the 

monitoring equipment manufacturer(s) 

and model numbers and the date of the 

last CMS certification or audit. 

(vi) The total fuel use by each 

individual boiler or process heater 

subject to an emission limit within the 

reporting period, including, but not 

limited to, a description of the fuel, 

whether the fuel has received a nonwaste determination by the EPA or your 

basis for concluding that the fuel is not 

a waste, and the total fuel usage amount 

with units of measure. 

(vii) If you are conducting 

performance tests once every 3 years 

consistent with § 63.7515(b) or (c), the 

date of the last 2 performance tests and 

a statement as to whether there have 

been any operational changes since the 

last performance test that could increase 

emissions. 

(viii) A statement indicating that you 

burned no new types of fuel in an 

individual boiler or process heater 

subject to an emission limit. Or, if you 

did burn a new type of fuel and are 

subject to a HCl emission limit, you 

must submit the calculation of chlorine 

input, using Equation 7 of § 63.7530, 

that demonstrates that your source is 

still within its maximum chlorine input 

level established during the previous 

performance testing (for sources that 

demonstrate compliance through 

performance testing) or you must submit 

the calculation of HCl emission rate 

using Equation 12 of § 63.7530 that 

demonstrates that your source is still 

meeting the emission limit for HCl 

emissions (for boilers or process heaters 

that demonstrate compliance through 

fuel analysis). If you burned a new type 

of fuel and are subject to a mercury 

emission limit, you must submit the 

calculation of mercury input, using 

Equation 8 of § 63.7530, that 

demonstrates that your source is still 

within its maximum mercury input 

level established during the previous 

performance testing (for sources that 

demonstrate compliance through 

performance testing), or you must 

submit the calculation of mercury 

emission rate using Equation 13 of 

§ 63.7530 that demonstrates that your 

source is still meeting the emission limit 

for mercury emissions (for boilers or 

process heaters that demonstrate 

compliance through fuel analysis). If 

you burned a new type of fuel and are 

subject to a TSM emission limit, you 

must submit the calculation of TSM 

input, using Equation 9 of § 63.7530, 

that demonstrates that your source is 

still within its maximum TSM input 

level established during the previous 

performance testing (for sources that 

demonstrate compliance through 

performance testing), or you must 

submit the calculation of TSM emission 

rate, using Equation 14 of § 63.7530, that 

demonstrates that your source is still 

meeting the emission limit for TSM 

emissions (for boilers or process heaters 

that demonstrate compliance through 

fuel analysis). 

(ix) If you wish to burn a new type of 

fuel in an individual boiler or process 

heater subject to an emission limit and 

you cannot demonstrate compliance 

with the maximum chlorine input 

operating limit using Equation 7 of 

§ 63.7530 or the maximum mercury 

input operating limit using Equation 8 

of § 63.7530, or the maximum TSM 

input operating limit using Equation 9 

of § 63.7530 you must include in the 

compliance report a statement 

indicating the intent to conduct a new 

performance test within 60 days of 

starting to burn the new fuel. 

(x) A summary of any monthly fuel 

analyses conducted to demonstrate 

compliance according to §§ 63.7521 and 

63.7530 for individual boilers or process 

heaters subject to emission limits, and 

any fuel specification analyses 

conducted according to §§ 63.7521(f) 

and 63.7530(g). 

(xi) If there are no deviations from any 

emission limits or operating limits in 

this subpart that apply to you, a 

statement that there were no deviations 

from the emission limits or operating 

limits during the reporting period. 

(xii) If there were no deviations from 

the monitoring requirements including 

no periods during which the CMSs, 

including CEMS, COMS, and CPMS, 

were out of control as specified in 

§ 63.8(c)(7), a statement that there were 

no deviations and no periods during 

which the CMS were out of control 

during the reporting period. 

(xiii) If a malfunction occurred during 

the reporting period, the report must 

include the number, duration, and a 

brief description for each type of 

malfunction which occurred during the 

reporting period and which caused or 


tkelley on DSK3SPTVN1PROD with 
Federal Register / Vol. 78, No. 21 / Thursday, January 31, 2013 / Rules and Regulations 7185 

may have caused any applicable 

emission limitation to be exceeded. The 

report must also include a description of 

actions taken by you during a 

malfunction of a boiler, process heater, 

or associated air pollution control 

device or CMS to minimize emissions in 

accordance with § 63.7500(a)(3), 

including actions taken to correct the 

malfunction. 

(xiv) Include the date of the most 

recent tune-up for each unit subject to 

only the requirement to conduct an 

annual, biennial, or 5-year tune-up 

according to § 63.7540(a)(10), (11), or 

(12) respectively. Include the date of the 

most recent burner inspection if it was 

not done annually, biennially, or on a 5- 

year period and was delayed until the 

next scheduled or unscheduled unit 

shutdown. 

(xv) If you plan to demonstrate 

compliance by emission averaging, 

certify the emission level achieved or 

the control technology employed is no 

less stringent than the level or control 

technology contained in the notification 

of compliance status in 

§ 63.7545(e)(5)(i). 

(xvi) For each reporting period, the 

compliance reports must include all of 

the calculated 30 day rolling average 

values based on the daily CEMS (CO 

and mercury) and CPMS (PM CPMS 

output, scrubber pH, scrubber liquid 

flow rate, scrubber pressure drop) data. 

(xvii) Statement by a responsible 

official with that official’s name, title, 

and signature, certifying the truth, 

accuracy, and completeness of the 

content of the report. 

(d) For each deviation from an 

emission limit or operating limit in this 

subpart that occurs at an individual 

boiler or process heater where you are 

not using a CMS to comply with that 

emission limit or operating limit, the 

compliance report must additionally 

contain the information required in 

paragraphs (d)(1) through (3) of this 

section. 

(1) A description of the deviation and 

which emission limit or operating limit 

from which you deviated. 

(2) Information on the number, 

duration, and cause of deviations 

(including unknown cause), as 

applicable, and the corrective action 

taken. 

(3) If the deviation occurred during an 

annual performance test, provide the 

date the annual performance test was 

completed. 

(e) For each deviation from an 

emission limit, operating limit, and 

monitoring requirement in this subpart 

occurring at an individual boiler or 

process heater where you are using a 

CMS to comply with that emission limit 

or operating limit, the compliance 

report must additionally contain the 

information required in paragraphs 

(e)(1) through (9) of this section. This 

includes any deviations from your sitespecific monitoring plan as required in 

§ 63.7505(d). 

(1) The date and time that each 

deviation started and stopped and 

description of the nature of the 

deviation (i.e., what you deviated from). 

(2) The date and time that each CMS 

was inoperative, except for zero (lowlevel) and high-level checks. 

(3) The date, time, and duration that 

each CMS was out of control, including 

the information in § 63.8(c)(8). 

(4) The date and time that each 

deviation started and stopped. 

(5) A summary of the total duration of 

the deviation during the reporting 

period and the total duration as a 

percent of the total source operating 

time during that reporting period. 

(6) A characterization of the total 

duration of the deviations during the 

reporting period into those that are due 

to control equipment problems, process 

problems, other known causes, and 

other unknown causes. 

(7) A summary of the total duration of 

CMS’s downtime during the reporting 

period and the total duration of CMS 

downtime as a percent of the total 

source operating time during that 

reporting period. 

(8) A brief description of the source 

for which there was a deviation. 

(9) A description of any changes in 

CMSs, processes, or controls since the 

last reporting period for the source for 

which there was a deviation. 

(f) [Reserved] 

(g) [Reserved] 

(h) You must submit the reports 

according to the procedures specified in 

paragraphs (h)(1) through (3) of this 

section. 

(1) Within 60 days after the date of 

completing each performance test 

(defined in § 63.2) as required by this 

subpart you must submit the results of 

the performance tests, including any 

associated fuel analyses, required by 

this subpart and the compliance reports 

required in § 63.7550(b) to the EPA’s 

WebFIRE database by using the 

Compliance and Emissions Data 

Reporting Interface (CEDRI) that is 

accessed through the EPA’s Central Data 

Exchange (CDX) (www.epa.gov/cdx). 

Performance test data must be submitted 

in the file format generated through use 

of the EPA’s Electronic Reporting Tool 

(ERT) (see http://www.epa.gov/ttn/chief/ 

ert/index.html). Only data collected 

using test methods on the ERT Web site 

are subject to this requirement for 

submitting reports electronically to 

WebFIRE. Owners or operators who 

claim that some of the information being 

submitted for performance tests is 

confidential business information (CBI) 

must submit a complete ERT file 

including information claimed to be CBI 

on a compact disk or other commonly 

used electronic storage media 

(including, but not limited to, flash 

drives) to the EPA. The electronic media 

must be clearly marked as CBI and 

mailed to U.S. EPA/OAPQS/CORE CBI 

Office, Attention: WebFIRE 

Administrator, MD C404–02, 4930 Old 

Page Rd., Durham, NC 27703. The same 

ERT file with the CBI omitted must be 

submitted to the EPA via CDX as 

described earlier in this paragraph. At 

the discretion of the Administrator, you 

must also submit these reports, 

including the confidential business 

information, to the Administrator in the 

format specified by the Administrator. 

For any performance test conducted 

using test methods that are not listed on 

the ERT Web site, the owner or operator 

shall submit the results of the 

performance test in paper submissions 

to the Administrator. 

(2) Within 60 days after the date of 

completing each CEMS performance 

evaluation test (defined in 63.2) you 

must submit the relative accuracy test 

audit (RATA) data to the EPA’s Central 

Data Exchange by using CEDRI as 

mentioned in paragraph (h)(1) of this 

section. Only RATA pollutants that can 

be documented with the ERT (as listed 

on the ERT Web site) are subject to this 

requirement. For any performance 

evaluations with no corresponding 

RATA pollutants listed on the ERT Web 

site, the owner or operator shall submit 

the results of the performance 

evaluation in paper submissions to the 

Administrator. 

(3) You must submit all reports 

required by Table 9 of this subpart 

electronically using CEDRI that is 

accessed through the EPA’s Central Data 

Exchange (CDX) (www.epa.gov/cdx). 

However, if the reporting form specific 

to this subpart is not available in CEDRI 

at the time that the report is due the 

report you must submit the report to the 

Administrator at the appropriate 

address listed in § 63.13. At the 

discretion of the Administrator, you 

must also submit these reports, to the 

Administrator in the format specified by 

the Administrator. 

■ 25. Section 63.7555 is amended by: 

■ a. Revising paragraphs (d) 

introductory text and (d)(2) through (6). 

■ b. Adding paragraphs (d)(9) through 

(11). 

■ c. Revising paragraphs (f) through (h). 

■ d. Adding paragraphs (i) and (j). 


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The revisions and additions read as 

follows: 

§ 63.7555 What records must I keep? 

* * * * * 

(d) For each boiler or process heater 

subject to an emission limit in Tables 1, 

2, or 11 through 13 to this subpart, you 

must also keep the applicable records in 

paragraphs (d)(1) through (11) of this 

section. 

* * * * * 

(2) If you combust non-hazardous 

secondary materials that have been 

determined not to be solid waste 

pursuant to § 241.3(b)(1) and (2) of this 

chapter, you must keep a record that 

documents how the secondary material 

meets each of the legitimacy criteria 

under § 241.3(d)(1) of this chapter. If 

you combust a fuel that has been 

processed from a discarded nonhazardous secondary material pursuant 

to § 241.3(b)(4) of this chapter, you must 

keep records as to how the operations 

that produced the fuel satisfy the 

definition of processing in § 241.2 of 

this chapter. If the fuel received a nonwaste determination pursuant to the 

petition process submitted under 

§ 241.3(c) of this chapter, you must keep 

a record that documents how the fuel 

satisfies the requirements of the petition 

process. For operating units that 

combust non-hazardous secondary 

materials as fuel per § 241.4 of this 

chapter, you must keep records 

documenting that the material is listed 

as a non-waste under § 241.4(a) of this 

chapter. Units exempt from the 

incinerator standards under section 

129(g)(1) of the Clean Air Act because 

they are qualifying facilities burning a 

homogeneous waste stream do not need 

to maintain the records described in this 

paragraph (d)(2). 

(3) For units in the limited use 

subcategory, you must keep a copy of 

the federally enforceable permit that 

limits the annual capacity factor to less 

than or equal to 10 percent and fuel use 

records for the days the boiler or process 

heater was operating. 

(4) A copy of all calculations and 

supporting documentation of maximum 

chlorine fuel input, using Equation 7 of 

§ 63.7530, that were done to 

demonstrate continuous compliance 

with the HCl emission limit, for sources 

that demonstrate compliance through 

performance testing. For sources that 

demonstrate compliance through fuel 

analysis, a copy of all calculations and 

supporting documentation of HCl 

emission rates, using Equation 12 of 

§ 63.7530, that were done to 

demonstrate compliance with the HCl 

emission limit. Supporting 

documentation should include results of 

any fuel analyses and basis for the 

estimates of maximum chlorine fuel 

input or HCl emission rates. You can 

use the results from one fuel analysis for 

multiple boilers and process heaters 

provided they are all burning the same 

fuel type. However, you must calculate 

chlorine fuel input, or HCl emission 

rate, for each boiler and process heater. 

(5) A copy of all calculations and 

supporting documentation of maximum 

mercury fuel input, using Equation 8 of 

§ 63.7530, that were done to 

demonstrate continuous compliance 

with the mercury emission limit for 

sources that demonstrate compliance 

through performance testing. For 

sources that demonstrate compliance 

through fuel analysis, a copy of all 

calculations and supporting 

documentation of mercury emission 

rates, using Equation 13 of § 63.7530, 

that were done to demonstrate 

compliance with the mercury emission 

limit. Supporting documentation should 

include results of any fuel analyses and 

basis for the estimates of maximum 

mercury fuel input or mercury emission 

rates. You can use the results from one 

fuel analysis for multiple boilers and 

process heaters provided they are all 

burning the same fuel type. However, 

you must calculate mercury fuel input, 

or mercury emission rates, for each 

boiler and process heater. 

(6) If, consistent with § 63.7515(b), 

you choose to stack test less frequently 

than annually, you must keep a record 

that documents that your emissions in 

the previous stack test(s) were less than 

75 percent of the applicable emission 

limit (or, in specific instances noted in 

Tables 1 and 2 or 11 through 13 to this 

subpart, less than the applicable 

emission limit), and document that 

there was no change in source 

operations including fuel composition 

and operation of air pollution control 

equipment that would cause emissions 

of the relevant pollutant to increase 

within the past year. 

* * * * * 

(9) A copy of all calculations and 

supporting documentation of maximum 

TSM fuel input, using Equation 9 of 

§ 63.7530, that were done to 

demonstrate continuous compliance 

with the TSM emission limit for sources 

that demonstrate compliance through 

performance testing. For sources that 

demonstrate compliance through fuel 

analysis, a copy of all calculations and 

supporting documentation of TSM 

emission rates, using Equation 14 of 

§ 63.7530, that were done to 

demonstrate compliance with the TSM 

emission limit. Supporting 

documentation should include results of 

any fuel analyses and basis for the 

estimates of maximum TSM fuel input 

or TSM emission rates. You can use the 

results from one fuel analysis for 

multiple boilers and process heaters 

provided they are all burning the same 

fuel type. However, you must calculate 

TSM fuel input, or TSM emission rates, 

for each boiler and process heater. 

(10) You must maintain records of the 

calendar date, time, occurrence and 

duration of each startup and shutdown. 

(11) You must maintain records of the 

type(s) and amount(s) of fuels used 

during each startup and shutdown. 

* * * * * 

(f) If you elect to use efficiency credits 

from energy conservation measures to 

demonstrate compliance according to 

§ 63.7533, you must keep a copy of the 

Implementation Plan required in 

§ 63.7533(d) and copies of all data and 

calculations used to establish credits 

according to § 63.7533(b), (c), and (f). 

(g) If you elected to demonstrate that 

the unit meets the specification for 

mercury for the unit designed to burn 

gas 1 subcategory, you must maintain 

monthly records (or at the frequency 

required by § 63.7540(c)) of the 

calculations and results of the fuel 

specification for mercury in Table 6. 

(h) If you operate a unit in the unit 

designed to burn gas 1 subcategory that 

is subject to this subpart, and you use 

an alternative fuel other than natural 

gas, refinery gas, gaseous fuel subject to 

another subpart under this part, other 

gas 1 fuel, or gaseous fuel subject to 

another subpart of this part or part 60, 

61, or 65, you must keep records of the 

total hours per calendar year that 

alternative fuel is burned and the total 

hours per calendar year that the unit 

operated during periods of gas 

curtailment or gas supply emergencies. 

(i) You must maintain records of the 

calendar date, time, occurrence and 

duration of each startup and shutdown. 

(j) You must maintain records of the 

type(s) and amount(s) of fuels used 

during each startup and shutdown. 

■ 26. Section 63.7570 is amended by 

revising paragraph (a) and paragraph (b) 

introductory text to read as follows: 

§ 63.7570 Who implements and enforces 

this subpart? 

(a) This subpart can be implemented 

and enforced by the EPA, or an 

Administrator such as your state, local, 

or tribal agency. If the EPA 

Administrator has delegated authority to 

your state, local, or tribal agency, then 

that agency (as well as the EPA) has the 

authority to implement and enforce this 

subpart. You should contact your EPA 

Regional Office to find out if this 


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Federal Register / Vol. 78, No. 21 / Thursday, January 31, 2013 / Rules and Regulations 7187 

subpart is delegated to your state, local, 

or tribal agency. 

(b) In delegating implementation and 

enforcement authority of this subpart to 

a state, local, or tribal agency under 40 

CFR part 63, subpart E, the authorities 

listed in paragraphs (b)(1) through (5) of 

this section are retained by the EPA 

Administrator and are not transferred to 

the state, local, or tribal agency, 

however, the EPA retains oversight of 

this subpart and can take enforcement 

actions, as appropriate. 

* * * * * 

■ 27. Section 63.7575 is amended by: 

■ a. Adding in alphabetical order 

definitions for ‘‘10-day rolling average,’’ 

‘‘30-day rolling average,’’ ‘‘Annual 

capacity factor,’’ ‘‘Average annual heat 

input rate,’’ ‘‘Benchmark,’’ ‘‘Biodiesel,’’ 

‘‘Daily block average,’’ ‘‘Efficiency 

credit,’’ ‘‘Energy management program,’’ 

‘‘Fluidized bed boiler with an integrated 

fluidized bed heat exchanger,’’ ‘‘Heavy 

liquid,’’ ‘‘Light liquid,’’ ’’ ‘‘Major source 

for oil and natural gas production 

facilities,’’ ‘‘Minimum oxygen level,’’ 

‘‘Other combustor’’, ‘‘Oxygen analyzer 

system’’, ‘‘Oxygen trim system’’, ‘‘Pile 

burner’’, ‘‘Regulated gas stream’’, 

‘‘Residential boiler,’’ ‘‘Residual oil’’, 

‘‘Secondary material,’’ ‘‘Shutdown’’, 

‘‘Sloped grate’’, ‘‘Startup’’, ‘‘Stoker/ 

sloped grate/other unit designed to burn 

kiln dried biomass,’’ Stoker/sloped 

grate/other unit designed to burn wet 

biomass,’’ ‘‘Suspension burner,’’ ‘‘Total 

selected metals (TSM),’’ ‘‘Traditional 

fuel,’’ ‘‘Ultra low sulfur liquid fuel,’’ 

‘‘Unit designed to burn heavy liquid 

subcategory,’’ ‘‘Unit designed to burn 

light liquid subcategory,’’ and 

‘‘Vegetable oil.’’ 

■ b. Revising the definitions for 

‘‘Boiler,’’ ‘‘Boiler system,’’ ‘‘Coal,’’ 

Commercial/institutional boiler,’’ 

‘‘Deviation,’’ ‘‘Distillate oil,’’ ‘‘Dry 

scrubber,’’ ‘‘Dutch oven,’’ ‘‘Electric 

utility steam generating unit,’’ ‘‘Energy 

assessment,’’ ‘‘Energy use system,’’ 

‘‘Equivalent,’’ ‘‘Federally enforceable,’’ 

‘‘Fluidized bed boiler’’, ‘‘Fuel cell,’’ 

‘‘Fuel type,’’ ‘‘Gaseous fuel,’’ ‘‘Heat 

input,’’ ‘‘Hot water heater,’’ ‘‘Hybrid 

suspension grate boiler,’’ ‘‘Industrial 

boiler,’’ ‘‘Limited-use boiler or process 

heater,’’ ‘‘Liquid fuel,’’ ‘‘Load fraction,’’ 

‘‘Metal process furnaces,’’ ‘‘Minimum 

activated carbon injection rate,’’ 

‘‘Minimum scrubber liquid flow rate,’’ 

‘‘Minimum sorbent injection rate,’’ 

‘‘Natural gas,’’ ‘‘Other gas 1 fuel,’’ 

‘‘Period of natural gas curtailment or 

supply interruption,’’ ‘‘Process heater,’’ 

‘‘Qualified energy assessor,’’ ‘‘Residual 

oil,’’ ‘‘Solid fossil fuel,’’ ‘‘Steam 

output,’’ ‘‘Stoker,’’ ‘‘Temporary boiler,’’ 

‘‘Tune-up,’’ ‘‘Unit designed to burn gas 

1 subcategory,’’ ‘‘Unit designed to burn 

gas 2 (other) subcategory,’’ ‘‘Unit 

designed to burn liquid subcategory,’’ 

‘‘Unit designed to burn liquid fuel that 

is a non-continental unit,’’ ‘‘Unit 

designed to burn solid fuel,’’ ‘‘Waste 

heat boiler,’’ ‘‘Waste heat process 

heater.’’ 

■ c. Removing the definitions for 

‘‘Benchmarking,’’ ‘‘Emission credit,’’ 

‘‘Liquid fuel subcategory,’’ and 

‘‘Suspension boiler.’’ 

The revisions read as follows: 

§ 63.7575 What definitions apply to this 

subpart? 

* * * * * 

10-day rolling average means the 

arithmetic mean of the previous 240 

hours of valid operating data. Valid data 

excludes hours during startup and 

shutdown, data collected during periods 

when the monitoring system is out of 

control as specified in your site-specific 

monitoring plan, while conducting 

repairs associated with periods when 

the monitoring system is out of control, 

or while conducting required 

monitoring system quality assurance or 

quality control activities, and periods 

when this unit is not operating. The 240 

hours should be consecutive, but not 

necessarily continuous if operations 

were intermittent. 

30-day rolling average means the 

arithmetic mean of the previous 720 

hours of valid operating data. Valid data 

excludes hours during startup and 

shutdown, data collected during periods 

when the monitoring system is out of 

control as specified in your site-specific 

monitoring plan, while conducting 

repairs associated with periods when 

the monitoring system is out of control, 

or while conducting required 

monitoring system quality assurance or 

quality control activities, and periods 

when this unit is not operating. The 720 

hours should be consecutive, but not 

necessarily continuous if operations 

were intermittent. 

* * * * * 

Annual capacity factor means the 

ratio between the actual heat input to a 

boiler or process heater from the fuels 

burned during a calendar year and the 

potential heat input to the boiler or 

process heater had it been operated for 

8,760 hours during a year at the 

maximum steady state design heat input 

capacity. 

Average annual heat input rate means 

total heat input divided by the hours of 

operation for the 12 months preceding 

the compliance demonstration. 

* * * * * 

Benchmark means the fuel heat input 

for a boiler or process heater for the oneyear period before the date that an 

energy demand reduction occurs, unless 

it can be demonstrated that a different 

time period is more representative of 

historical operations. 

Biodiesel means a mono-alkyl ester 

derived from biomass and conforming to 

ASTM D6751–11b, Standard 

Specification for Biodiesel Fuel Blend 

Stock (B100) for Middle Distillate Fuels 

(incorporated by reference, see § 63.14). 

* * * * * 

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. Controlled flame 

combustion refers to a steady-state, or 

near steady-state, process wherein fuel 

and/or oxidizer feed rates are 

controlled. A device combusting solid 

waste, as defined in § 241.3 of this 

chapter, is not a boiler unless the device 

is exempt from the definition of a solid 

waste incineration unit as provided in 

section 129(g)(1) of the Clean Air Act. 

Waste heat boilers are excluded from 

this definition. 

Boiler system means the boiler and 

associated components, such as, the 

feed water system, the combustion air 

system, the fuel system (including 

burners), blowdown system, combustion 

control systems, steam systems, and 

condensate return systems. 

* * * * * 

Coal means all solid fuels classifiable 

as anthracite, bituminous, subbituminous, or lignite by ASTM D388 

(incorporated by reference, see § 63.14), 

coal refuse, and petroleum coke. For the 

purposes of this subpart, this definition 

of ‘‘coal’’ includes synthetic fuels 

derived from coal, including but not 

limited to, solvent-refined coal, coal-oil 

mixtures, and coal-water mixtures. Coal 

derived gases are excluded from this 

definition. 

* * * * * 

Commercial/institutional boiler 

means a boiler used in commercial 

establishments or institutional 

establishments such as medical centers, 

nursing homes, research centers, 

institutions of higher education, 

elementary and secondary schools, 

libraries, religious establishments, 

governmental buildings, hotels, 

restaurants, and laundries to provide 

electricity, steam, and/or hot water. 

* * * * * 

Daily block average means the 

arithmetic mean of all valid emission 

concentrations or parameter levels 

recorded when a unit is operating 

measured over the 24-hour period from 

12 a.m. (midnight) to 12 a.m. 

(midnight), except for periods of startup 

and shutdown or downtime. 


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Deviation. 

(1) Deviation means any instance in 

which an affected source subject to this 

subpart, or an owner or operator of such 

a source: 

(i) Fails to meet any applicable 

requirement or obligation established by 

this subpart including, but not limited 

to, any emission limit, operating limit, 

or work practice standard; or 

(ii) Fails to meet any term or 

condition that is adopted to implement 

an applicable requirement in this 

subpart and that is included in the 

operating permit for any affected source 

required to obtain such a permit. 

(2) A deviation is not always a 

violation. 

* * * * * 

Distillate oil means fuel oils that 

contain 0.05 weight percent nitrogen or 

less and comply with the specifications 

for fuel oil numbers 1 and 2, as defined 

by the American Society of Testing and 

Materials in ASTM D396 (incorporated 

by reference, see § 63.14) or diesel fuel 

oil numbers 1 and 2, as defined by the 

American Society for Testing and 

Materials in ASTM D975 (incorporated 

by reference, see § 63.14), kerosene, and 

biodiesel as defined by the American 

Society of Testing and Materials in 

ASTM D6751–11b (incorporated by 

reference, see § 60.14). 

Dry scrubber means an add-on air 

pollution control system that injects dry 

alkaline sorbent (dry injection) or sprays 

an alkaline sorbent (spray dryer) to react 

with and neutralize acid gas in the 

exhaust stream forming a dry powder 

material. Sorbent injection systems used 

as control devices in fluidized bed 

boilers and process heaters are included 

in this definition. A dry scrubber is a 

dry control system. 

Dutch oven means a unit having a 

refractory-walled cell connected to a 

conventional boiler setting. Fuel 

materials are introduced through an 

opening in the roof of the dutch oven 

and burn in a pile on its floor. Fluidized 

bed boilers are not part of the dutch 

oven design category. 

Electric utility steam generating unit 

(EGU) means a fossil fuel-fired 

combustion unit of more than 25 

megawatts electric (MWe) that serves a 

generator that produces electricity for 

sale. A fossil fuel-fired unit that 

cogenerates steam and electricity and 

supplies more than one-third of its 

potential electric output capacity and 

more than 25 MWe output to any utility 

power distribution system for sale is 

considered an electric utility steam 

generating unit. To be ‘‘capable of 

combusting’’ fossil fuels, an EGU would 

need to have these fuels allowed in their 

operating permits and have the 

appropriate fuel handling facilities onsite or otherwise available (e.g., coal 

handling equipment, including coal 

storage area, belts and conveyers, 

pulverizers, etc.; oil storage facilities). In 

addition, fossil fuel-fired EGU means 

any EGU that fired fossil fuel for more 

than 10.0 percent of the average annual 

heat input in any 3 consecutive calendar 

years or for more than 15.0 percent of 

the annual heat input during any one 

calendar year after April 16, 2012. 

* * * * * 

Efficiency credit means emission 

reductions above those required by this 

subpart. Efficiency credits generated 

may be used to comply with the 

emissions limits. Credits may come 

from pollution prevention projects that 

result in reduced fuel use by affected 

units. Boilers that are shut down cannot 

be used to generate credits unless the 

facility provides documentation linking 

the permanent shutdown to 

implementation of the energy 

conservation measures identified in the 

energy assessment. 

Energy assessment means the 

following for the emission units covered 

by this subpart: 

(1) The energy assessment for 

facilities with affected boilers and 

process heaters with a combined heat 

input capacity of less than 0.3 trillion 

Btu (TBtu) per year will be 8 on-site 

technical labor hours in length 

maximum, but may be longer at the 

discretion of the owner or operator of 

the affected source. The boiler system(s) 

and any on-site energy use system(s) 

accounting for at least 50 percent of the 

affected boiler(s) energy (e.g., steam, hot 

water, process heat, or electricity) 

production, as applicable, will be 

evaluated to identify energy savings 

opportunities, within the limit of 

performing an 8-hour on-site energy 

assessment. 

(2) The energy assessment for 

facilities with affected boilers and 

process heaters with a combined heat 

input capacity of 0.3 to 1.0 TBtu/year 

will be 24 on-site technical labor hours 

in length maximum, but may be longer 

at the discretion of the owner or 

operator of the affected source. The 

boiler system(s) and any on-site energy 

use system(s) accounting for at least 33 

percent of the energy (e.g., steam, hot 

water, process heat, or electricity) 

production, as applicable, will be 

evaluated to identify energy savings 

opportunities, within the limit of 

performing a 24-hour on-site energy 

assessment. 

(3) The energy assessment for 

facilities with affected boilers and 

process heaters with a combined heat 

input capacity greater than 1.0 TBtu/ 

year will be up to 24 on-site technical 

labor hours in length for the first TBtu/ 

yr plus 8 on-site technical labor hours 

for every additional 1.0 TBtu/yr not to 

exceed 160 on-site technical hours, but 

may be longer at the discretion of the 

owner or operator of the affected source. 

The boiler system(s), process heater(s), 

and any on-site energy use system(s) 

accounting for at least 20 percent of the 

energy (e.g., steam, process heat, hot 

water, or electricity) production, as 

applicable, will be evaluated to identify 

energy savings opportunities. 

(4) The on-site energy use systems 

serving as the basis for the percent of 

affected boiler(s) and process heater(s) 

energy production in paragraphs (1), (2), 

and (3) of this definition may be 

segmented by production area or energy 

use area as most logical and applicable 

to the specific facility being assessed 

(e.g., product X manufacturing area; 

product Y drying area; Building Z). 

* * * * * 

Energy management program means a 

program that includes a set of practices 

and procedures designed to manage 

energy use that are demonstrated by the 

facility’s energy policies, a facility 

energy manager and other staffing 

responsibilities, energy performance 

measurement and tracking methods, an 

energy saving goal, action plans, 

operating procedures, internal reporting 

requirements, and periodic review 

intervals used at the facility. Facilities 

may establish their program through 

energy management systems compatible 

with ISO 50001. 

Energy use system includes the 

following systems located on-site that 

use energy (steam, hot water, or 

electricity) provided by the affected 

boiler or process heater: process heating; 

compressed air systems; machine drive 

(motors, pumps, fans); process cooling; 

facility heating, ventilation, and airconditioning systems; hot water 

systems; building envelop; and lighting; 

or other systems that use steam, hot 

water, process heat, or electricity 

provided by the affected boiler or 

process heater. Energy use systems are 

only those systems using energy clearly 

produced by affected boilers and 

process heaters. 

Equivalent means the following only 

as this term is used in Table 6 to this 

subpart: 

(1) An equivalent sample collection 

procedure means a published voluntary 

consensus standard or practice (VCS) or 

EPA method that includes collection of 

a minimum of three composite fuel 

samples, with each composite 


tkelley on DSK3SPTVN1PROD with 
Federal Register / Vol. 78, No. 21 / Thursday, January 31, 2013 / Rules and Regulations 7189 

consisting of a minimum of three 

increments collected at approximately 

equal intervals over the test period. 

(2) An equivalent sample compositing 

procedure means a published VCS or 

EPA method to systematically mix and 

obtain a representative subsample (part) 

of the composite sample. 

(3) An equivalent sample preparation 

procedure means a published VCS or 

EPA method that: Clearly states that the 

standard, practice or method is 

appropriate for the pollutant and the 

fuel matrix; or is cited as an appropriate 

sample preparation standard, practice or 

method for the pollutant in the chosen 

VCS or EPA determinative or analytical 

method. 

(4) An equivalent procedure for 

determining heat content means a 

published VCS or EPA method to obtain 

gross calorific (or higher heating) value. 

(5) An equivalent procedure for 

determining fuel moisture content 

means a published VCS or EPA method 

to obtain moisture content. If the sample 

analysis plan calls for determining 

metals (especially the mercury, 

selenium, or arsenic) using an aliquot of 

the dried sample, then the drying 

temperature must be modified to 

prevent vaporizing these metals. On the 

other hand, if metals analysis is done on 

an ‘‘as received’’ basis, a separate 

aliquot can be dried to determine 

moisture content and the metals 

concentration mathematically adjusted 

to a dry basis. 

(6) An equivalent pollutant (mercury, 

HCl) determinative or analytical 

procedure means a published VCS or 

EPA method that clearly states that the 

standard, practice, or method is 

appropriate for the pollutant and the 

fuel matrix and has a published 

detection limit equal or lower than the 

methods listed in Table 6 to this subpart 

for the same purpose. 

* * * * * 

Federally enforceable means all 

limitations and conditions that are 

enforceable by the EPA Administrator, 

including, but not limited to, the 

requirements of 40 CFR parts 60, 61, 63, 

and 65, requirements within any 

applicable state implementation plan, 

and any permit requirements 

established under 40 CFR 52.21 or 

under 40 CFR 51.18 and 40 CFR 51.24. 

Fluidized bed boiler means a boiler 

utilizing a fluidized bed combustion 

process that is not a pulverized coal 

boiler. 

Fluidized bed boiler with an 

integrated fluidized bed heat exchanger 

means a boiler utilizing a fluidized bed 

combustion where the entire tube 

surface area is located outside of the 

furnace section at the exit of the cyclone 

section and exposed to the flue gas 

stream for conductive heat transfer. This 

design applies only to boilers in the unit 

designed to burn coal/solid fossil fuel 

subcategory that fire coal refuse. 

* * * * * 

Fuel cell means a boiler type in which 

the fuel is dropped onto suspended 

fixed grates and is fired in a pile. The 

refractory-lined fuel cell uses 

combustion air preheating and 

positioning of secondary and tertiary air 

injection ports to improve boiler 

efficiency. Fluidized bed, dutch oven, 

pile burner, hybrid suspension grate, 

and suspension burners are not part of 

the fuel cell subcategory. 

Fuel type means each category of fuels 

that share a common name or 

classification. Examples include, but are 

not limited to, bituminous coal, subbituminous coal, lignite, anthracite, 

biomass, distillate oil, residual oil. 

Individual fuel types received from 

different suppliers are not considered 

new fuel types. 

Gaseous fuel includes, but is not 

limited to, natural gas, process gas, 

landfill gas, coal derived gas, refinery 

gas, and biogas. Blast furnace gas and 

process gases that are regulated under 

another subpart of this part, or part 60, 

part 61, or part 65 of this chapter, are 

exempted from this definition. 

Heat input means heat derived from 

combustion of fuel in a boiler or process 

heater and does not include the heat 

input from preheated combustion air, 

recirculated flue gases, returned 

condensate, or exhaust gases from other 

sources such as gas turbines, internal 

combustion engines, kilns, etc. 

Heavy liquid includes residual oil and 

any other liquid fuel not classified as a 

light liquid. 

* * * * * 

Hot water heater means a closed 

vessel with a capacity of no more than 

120 U.S. gallons in which water is 

heated by combustion of gaseous, 

liquid, or biomass/bio-based solid fuel 

and is withdrawn for use external to the 

vessel. Hot water boilers (i.e., not 

generating steam) combusting gaseous, 

liquid, or biomass fuel with a heat input 

capacity of less than 1.6 million Btu per 

hour are included in this definition. The 

120 U.S. gallon capacity threshold to be 

considered a hot water heater is 

independent of the 1.6 MMBtu/hr heat 

input capacity threshold for hot water 

boilers. Hot water heater also means a 

tankless unit that provides on demand 

hot water. 

Hybrid suspension grate boiler means 

a boiler designed with air distributors to 

spread the fuel material over the entire 

width and depth of the boiler 

combustion zone. The biomass fuel 

combusted in these units exceeds a 

moisture content of 40 percent on an asfired annual heat input basis. The 

drying and much of the combustion of 

the fuel takes place in suspension, and 

the combustion is completed on the 

grate or floor of the boiler. Fluidized 

bed, dutch oven, and pile burner 

designs are not part of the hybrid 

suspension grate boiler design category. 

Industrial boiler means a boiler used 

in manufacturing, processing, mining, 

and refining or any other industry to 

provide steam, hot water, and/or 

electricity. 

Light liquid includes distillate oil, 

biodiesel, or vegetable oil. 

Limited-use boiler or process heater 

means any boiler or process heater that 

burns any amount of solid, liquid, or 

gaseous fuels and has a federally 

enforceable average annual capacity 

factor of no more than 10 percent. 

Liquid fuel includes, but is not 

limited to, light liquid, heavy liquid, 

any form of liquid fuel derived from 

petroleum, used oil, liquid biofuels, 

biodiesel, vegetable oil, and comparable 

fuels as defined under 40 CFR 261.38. 

Load fraction means the actual heat 

input of a boiler or process heater 

divided by heat input during the 

performance test that established the 

minimum sorbent injection rate or 

minimum activated carbon injection 

rate, expressed as a fraction (e.g., for 50 

percent load the load fraction is 0.5). 

Major source for oil and natural gas 

production facilities, as used in this 

subpart, shall have the same meaning as 

in § 63.2, except that: 

(1) Emissions from any oil or gas 

exploration or production well (with its 

associated equipment, as defined in this 

section), and emissions from any 

pipeline compressor station or pump 

station shall not be aggregated with 

emissions from other similar units to 

determine whether such emission 

points or stations are major sources, 

even when emission points are in a 

contiguous area or under common 

control; 

(2) Emissions from processes, 

operations, or equipment that are not 

part of the same facility, as defined in 

this section, shall not be aggregated; and 

(3) For facilities that are production 

field facilities, only HAP emissions from 

glycol dehydration units and storage 

vessels with the potential for flash 

emissions shall be aggregated for a 

major source determination. For 

facilities that are not production field 

facilities, HAP emissions from all HAP 

emission units shall be aggregated for a 

major source determination. 


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Metal process furnaces are a 

subcategory of process heaters, as 

defined in this subpart, which include 

natural gas-fired annealing furnaces, 

preheat furnaces, reheat furnaces, aging 

furnaces, heat treat furnaces, and 

homogenizing furnaces. 

* * * * * 

Minimum activated carbon injection 

rate means load fraction multiplied by 

the lowest hourly average activated 

carbon injection rate measured 

according to Table 7 to this subpart 

during the most recent performance test 

demonstrating compliance with the 

applicable emission limit. 

Minimum oxygen level means the 

lowest hourly average oxygen level 

measured according to Table 7 to this 

subpart during the most recent 

performance test demonstrating 

compliance with the applicable 

emission limit. 

* * * * * 

Minimum scrubber liquid flow rate 

means the lowest hourly average liquid 

flow rate (e.g., to the PM scrubber or to 

the acid gas scrubber) measured 

according to Table 7 to this subpart 

during the most recent performance 

stack test demonstrating compliance 

with the applicable emission limit. 

* * * * * 

Minimum sorbent injection rate 

means: 

(1) The load fraction multiplied by the 

lowest hourly average sorbent injection 

rate for each sorbent measured 

according to Table 7 to this subpart 

during the most recent performance test 

demonstrating compliance with the 

applicable emission limits; or 

(2) For fluidized bed combustion, the 

lowest average ratio of sorbent to sulfur 

measured during the most recent 

performance test. 

* * * * * 

Natural gas means: 

(1) A naturally occurring mixture of 

hydrocarbon and nonhydrocarbon gases 

found in geologic formations beneath 

the earth’s surface, of which the 

principal constituent is methane; or 

(2) Liquefied petroleum gas, as 

defined in ASTM D1835 (incorporated 

by reference, see § 63.14); or 

(3) A mixture of hydrocarbons that 

maintains a gaseous state at ISO 

conditions. Additionally, natural gas 

must either be composed of at least 70 

percent methane by volume or have a 

gross calorific value between 35 and 41 

megajoules (MJ) per dry standard cubic 

meter (950 and 1,100 Btu per dry 

standard cubic foot); or 

(4) Propane or propane derived 

synthetic natural gas. Propane means a 

colorless gas derived from petroleum 

and natural gas, with the molecular 

structure C3H8. 

* * * * * 

Other combustor means a unit 

designed to burn solid fuel that is not 

classified as a dutch oven, fluidized 

bed, fuel cell, hybrid suspension grate 

boiler, pulverized coal boiler, stoker, 

sloped grate, or suspension boiler as 

defined in this subpart. 

Other gas 1 fuel means a gaseous fuel 

that is not natural gas or refinery gas 

and does not exceed a maximum 

concentration of 40 micrograms/cubic 

meters of mercury. 

Oxygen analyzer system means all 

equipment required to determine the 

oxygen content of a gas stream and used 

to monitor oxygen in the boiler or 

process heater flue gas, boiler or process 

heater, firebox, or other appropriate 

location. This definition includes 

oxygen trim systems. The source owner 

or operator must install, calibrate, 

maintain, and operate the oxygen 

analyzer system in accordance with the 

manufacturer’s recommendations. 

Oxygen trim system means a system of 

monitors that is used to maintain excess 

air at the desired level in a combustion 

device. A typical system consists of a 

flue gas oxygen and/or CO monitor that 

automatically provides a feedback signal 

to the combustion air controller. 

* * * * * 

Period of gas curtailment or supply 

interruption means a period of time 

during which the supply of gaseous fuel 

to an affected boiler or process heater is 

restricted or halted for reasons beyond 

the control of the facility. The act of 

entering into a contractual agreement 

with a supplier of natural gas 

established for curtailment purposes 

does not constitute a reason that is 

under the control of a facility for the 

purposes of this definition. An increase 

in the cost or unit price of natural gas 

due to normal market fluctuations not 

during periods of supplier delivery 

restriction does not constitute a period 

of natural gas curtailment or supply 

interruption. On-site gaseous fuel 

system emergencies or equipment 

failures qualify as periods of supply 

interruption when the emergency or 

failure is beyond the control of the 

facility. 

Pile burner means a boiler design 

incorporating a design where the 

anticipated biomass fuel has a high 

relative moisture content. Grates serve 

to support the fuel, and underfire air 

flowing up through the grates provides 

oxygen for combustion, cools the grates, 

promotes turbulence in the fuel bed, 

and fires the fuel. The most common 

form of pile burning is the dutch oven. 

Process heater means an enclosed 

device using controlled flame, and the 

unit’s primary purpose is to transfer 

heat indirectly to a process material 

(liquid, gas, or solid) or to a heat transfer 

material (e.g., glycol or a mixture of 

glycol and water) for use in a process 

unit, instead of generating steam. 

Process heaters are devices in which the 

combustion gases do not come into 

direct contact with process materials. A 

device combusting solid waste, as 

defined in § 241.3 of this chapter, is not 

a process heater unless the device is 

exempt from the definition of a solid 

waste incineration unit as provided in 

section 129(g)(1) of the Clean Air Act. 

Process heaters do not include units 

used for comfort heat or space heat, food 

preparation for on-site consumption, or 

autoclaves. Waste heat process heaters 

are excluded from this definition. 

* * * * * 

Qualified energy assessor means: 

(1) Someone who has demonstrated 

capabilities to evaluate energy savings 

opportunities for steam generation and 

major energy using systems, including, 

but not limited to: 

(i) Boiler combustion management. 

(ii) Boiler thermal energy recovery, 

including 

(A) Conventional feed water 

economizer, 

(B) Conventional combustion air 

preheater, and 

(C) Condensing economizer. 

(iii) Boiler blowdown thermal energy 

recovery. 

(iv) Primary energy resource selection, 

including 

(A) Fuel (primary energy source) 

switching, and 

(B) Applied steam energy versus 

direct-fired energy versus electricity. 

(v) Insulation issues. 

(vi) Steam trap and steam leak 

management. 

(vi) Condensate recovery. 

(viii) Steam end-use management. 

(2) Capabilities and knowledge 

includes, but is not limited to: 

(i) Background, experience, and 

recognized abilities to perform the 

assessment activities, data analysis, and 

report preparation. 

(ii) Familiarity with operating and 

maintenance practices for steam or 

process heating systems. 

(iii) Additional potential steam 

system improvement opportunities 

including improving steam turbine 

operations and reducing steam demand. 

(iv) Additional process heating system 

opportunities including effective 

utilization of waste heat and use of 

proper process heating methods. 

(v) Boiler-steam turbine cogeneration 

systems. 


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Federal Register / Vol. 78, No. 21 / Thursday, January 31, 2013 / Rules and Regulations 7191 

(vi) Industry specific steam end-use 

systems. 

* * * * * 

Regulated gas stream means an offgas 

stream that is routed to a boiler or 

process heater for the purpose of 

achieving compliance with a standard 

under another subpart of this part or 

part 60, part 61, or part 65 of this 

chapter. 

Residential boiler means a boiler used 

to provide heat and/or hot water and/or 

as part of a residential combined heat 

and power system. This definition 

includes boilers located at an 

institutional facility (e.g., university 

campus, military base, church grounds) 

or commercial/industrial facility (e.g., 

farm) used primarily to provide heat 

and/or hot water for: 

(1) A dwelling containing four or 

fewer families; or 

(2) A single unit residence dwelling 

that has since been converted or 

subdivided into condominiums or 

apartments. 

Residual oil means crude oil, fuel oil 

that does not comply with the 

specifications under the definition of 

distillate oil, and all fuel oil numbers 4, 

5, and 6, as defined by the American 

Society of Testing and Materials in 

ASTM D396–10 (incorporated by 

reference, see § 63.14(b)). 

* * * * * 

Secondary material means the 

material as defined in § 241.2 of this 

chapter. 

Shutdown means the cessation of 

operation of a boiler or process heater 

for any purpose. Shutdown begins 

either when none of the steam from the 

boiler is supplied for heating and/or 

producing electricity, or for any other 

purpose, or at the point of no fuel being 

fired in the boiler or process heater, 

whichever is earlier. Shutdown ends 

when there is no steam and no heat 

being supplied and no fuel being fired 

in the boiler or process heater. 

Sloped grate means a unit where the 

solid fuel is fed to the top of the grate 

from where it slides downwards; while 

sliding the fuel first dries and then 

ignites and burns. The ash is deposited 

at the bottom of the grate. Fluidized bed, 

dutch oven, pile burner, hybrid 

suspension grate, suspension burners, 

and fuel cells are not considered to be 

a sloped grate design. 

Solid fossil fuel includes, but is not 

limited to, coal, coke, petroleum coke, 

and tire derived fuel. 

* * * * * 

Startup means either the first-ever 

firing of fuel in a boiler or process 

heater for the purpose of supplying 

steam or heat for heating and/or 

producing electricity, or for any other 

purpose, or the firing of fuel in a boiler 

after a shutdown event for any purpose. 

Startup ends when any of the steam or 

heat from the boiler or process heater is 

supplied for heating, and/or producing 

electricity, or for any other purpose. 

Steam output means: 

(1) For a boiler that produces steam 

for process or heating only (no power 

generation), the energy content in terms 

of MMBtu of the boiler steam output, 

(2) For a boiler that cogenerates 

process steam and electricity (also 

known as combined heat and power), 

the total energy output, which is the 

sum of the energy content of the steam 

exiting the turbine and sent to process 

in MMBtu and the energy of the 

electricity generated converted to 

MMBtu at a rate of 10,000 Btu per 

kilowatt-hour generated (10 MMBtu per 

megawatt-hour), and 

(3) For a boiler that generates only 

electricity, the alternate output-based 

emission limits would be calculated 

using Equations 21 through 25 of this 

section, as appropriate: 

(i) For emission limits for boilers in 

the unit designed to burn solid fuel 

subcategory use Equation 21 of this 

section: 

Where: 

ELOBE = Emission limit in units of pounds 

per megawatt-hour. 

ELT = Appropriate emission limit from Table 

1 or 2 of this subpart in units of pounds 

per million Btu heat input. 

(ii) For PM and CO emission limits for 

boilers in one of the subcategories of 

units designed to burn coal use 

Equation 22 of this section: 

Where: 

ELOBE = Emission limit in units of pounds 

per megawatt-hour. 

ELT = Appropriate emission limit from Table 

1 or 2 of this subpart in units of pounds 

per million Btu heat input. 

(iii) For PM and CO emission limits 

for boilers in one of the subcategories of 

units designed to burn biomass use 

Equation 23 of this section: 

Where: 

ELOBE = Emission limit in units of pounds 

per megawatt-hour. 

ELT = Appropriate emission limit from Table 

1 or 2 of this subpart in units of pounds 

per million Btu heat input. 

(iv) For emission limits for boilers in 

one of the subcategories of units 

designed to burn liquid fuels use 

Equation 24 of this section: 

Where: 

ELOBE = Emission limit in units of pounds 

per megawatt-hour. 

ELT = Appropriate emission limit from Table 

1 or 2 of this subpart in units of pounds 

per million Btu heat input. 

(v) For emission limits for boilers in 

the unit designed to burn gas 2 (other) 


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7192 Federal Register / Vol. 78, No. 21 / Thursday, January 31, 2013 / Rules and Regulations 

subcategory, use Equation 25 of this 

section: 

Where: 

ELOBE = Emission limit in units of pounds 

per megawatt-hour. 

ELT = Appropriate emission limit from Table 

1 or 2 of this subpart in units of pounds 

per million Btu heat input. 

Stoker means a unit consisting of a 

mechanically operated fuel feeding 

mechanism, a stationary or moving grate 

to support the burning of fuel and admit 

under-grate air to the fuel, an overfire 

air system to complete combustion, and 

an ash discharge system. This definition 

of stoker includes air swept stokers. 

There are two general types of stokers: 

Underfeed and overfeed. Overfeed 

stokers include mass feed and spreader 

stokers. Fluidized bed, dutch oven, pile 

burner, hybrid suspension grate, 

suspension burners, and fuel cells are 

not considered to be a stoker design. 

Stoker/sloped grate/other unit 

designed to burn kiln dried biomass 

means the unit is in the units designed 

to burn biomass/bio-based solid 

subcategory that is either a stoker, 

sloped grate, or other combustor design 

and is not in the stoker/sloped grate/ 

other units designed to burn wet 

biomass subcategory. 

Stoker/sloped grate/other unit 

designed to burn wet biomass means the 

unit is in the units designed to burn 

biomass/bio-based solid subcategory 

that is either a stoker, sloped grate, or 

other combustor design and any of the 

biomass/bio-based solid fuel combusted 

in the unit exceeds 20 percent moisture 

on an annual heat input basis. 

Suspension burner means a unit 

designed to fire dry biomass/biobased 

solid particles in suspension that are 

conveyed in an airstream to the furnace 

like pulverized coal. The combustion of 

the fuel material is completed on a grate 

or floor below. The biomass/biobased 

fuel combusted in the unit shall not 

exceed 20 percent moisture on an 

annual heat input basis. Fluidized bed, 

dutch oven, pile burner, and hybrid 

suspension grate units are not part of 

the suspension burner subcategory. 

Temporary boiler means any gaseous 

or liquid fuel boiler that is designed to, 

and is capable of, being carried or 

moved from one location to another by 

means of, for example, wheels, skids, 

carrying handles, dollies, trailers, or 

platforms. A boiler is not a temporary 

boiler if any one of the following 

conditions exists: 

(1) The equipment is attached to a 

foundation. 

(2) The boiler or a replacement 

remains at a location within the facility 

and performs the same or similar 

function for more than 12 consecutive 

months, unless the regulatory agency 

approves an extension. An extension 

may be granted by the regulating agency 

upon petition by the owner or operator 

of a unit specifying the basis for such a 

request. Any temporary boiler that 

replaces a temporary boiler at a location 

and performs the same or similar 

function will be included in calculating 

the consecutive time period. 

(3) The equipment is located at a 

seasonal facility and operates during the 

full annual operating period of the 

seasonal facility, remains at the facility 

for at least 2 years, and operates at that 

facility for at least 3 months each year. 

(4) The equipment is moved from one 

location to another within the facility 

but continues to perform the same or 

similar function and serve the same 

electricity, steam, and/or hot water 

system in an attempt to circumvent the 

residence time requirements of this 

definition. 

Total selected metals (TSM) means 

the sum of the following metallic 

hazardous air pollutants: arsenic, 

beryllium, cadmium, chromium, lead, 

manganese, nickel and selenium. 

Traditional fuel means the fuel as 

defined in § 241.2 of this chapter. 

Tune-up means adjustments made to 

a boiler or process heater in accordance 

with the procedures outlined in 

§ 63.7540(a)(10). 

* * * * * 

Ultra low sulfur liquid fuel means a 

distillate oil that has less than or equal 

to 15 ppm sulfur. 

* * * * * 

Unit designed to burn gas 1 

subcategory includes any boiler or 

process heater that burns only natural 

gas, refinery gas, and/or other gas 1 

fuels. Gaseous fuel boilers and process 

heaters that burn liquid fuel for periodic 

testing of liquid fuel, maintenance, or 

operator training, not to exceed a 

combined total of 48 hours during any 

calendar year, are included in this 

definition. Gaseous fuel boilers and 

process heaters that burn liquid fuel 

during periods of gas curtailment or gas 

supply interruptions of any duration are 

also included in this definition. 

Unit designed to burn gas 2 (other) 

subcategory includes any boiler or 

process heater that is not in the unit 

designed to burn gas 1 subcategory and 

burns any gaseous fuels either alone or 

in combination with less than 10 

percent coal/solid fossil fuel, and less 

than 10 percent biomass/bio-based solid 

fuel on an annual heat input basis, and 

no liquid fuels. Gaseous fuel boilers and 

process heaters that are not in the unit 

designed to burn gas 1 subcategory and 

that burn liquid fuel for periodic testing 

of liquid fuel, maintenance, or operator 

training, not to exceed a combined total 

of 48 hours during any calendar year, 

are included in this definition. Gaseous 

fuel boilers and process heaters that are 

not in the unit designed to burn gas 1 

subcategory and that burn liquid fuel 

during periods of gas curtailment or gas 

supply interruption of any duration are 

also included in this definition. 

Unit designed to burn heavy liquid 

subcategory means a unit in the unit 

designed to burn liquid subcategory 

where at least 10 percent of the heat 

input from liquid fuels on an annual 

heat input basis comes from heavy 

liquids. 

Unit designed to burn light liquid 

subcategory means a unit in the unit 

designed to burn liquid subcategory that 

is not part of the unit designed to burn 

heavy liquid subcategory. 

Unit designed to burn liquid 

subcategory includes any boiler or 

process heater that burns any liquid 

fuel, but less than 10 percent coal/solid 

fossil fuel and less than 10 percent 

biomass/bio-based solid fuel on an 

annual heat input basis, either alone or 

in combination with gaseous fuels. 

Units in the unit design to burn gas 1 

or unit designed to burn gas 2 (other) 

subcategories that burn liquid fuel for 

periodic testing of liquid fuel, 

maintenance, or operator training, not to 

exceed a combined total of 48 hours 

during any calendar year are not 

included in this definition. Units in the 

unit design to burn gas 1 or unit 

designed to burn gas 2 (other) 

subcategories during periods of gas 

curtailment or gas supply interruption 

of any duration are also not included in 

this definition. 

Unit designed to burn liquid fuel that 

is a non-continental unit means an 

industrial, commercial, or institutional 

boiler or process heater meeting the 

definition of the unit designed to burn 


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liquid subcategory located in the State 

of Hawaii, the Virgin Islands, Guam, 

American Samoa, the Commonwealth of 

Puerto Rico, or the Northern Mariana 

Islands. 

Unit designed to burn solid fuel 

subcategory means any boiler or process 

heater that burns only solid fuels or at 

least 10 percent solid fuel on an annual 

heat input basis in combination with 

liquid fuels or gaseous fuels. 

Vegetable oil means oils extracted 

from vegetation. 

* * * * * 

Waste heat boiler means a device that 

recovers normally unused energy (i.e., 

hot exhaust gas) and converts it to 

usable heat. Waste heat boilers are also 

referred to as heat recovery steam 

generators. Waste heat boilers are heat 

exchangers generating steam from 

incoming hot exhaust gas from an 

industrial (e.g., thermal oxidizer, kiln, 

furnace) or power (e.g., combustion 

turbine, engine) equipment. Duct 

burners are sometimes used to increase 

the temperature of the incoming hot 

exhaust gas. 

Waste heat process heater means an 

enclosed device that recovers normally 

unused energy (i.e., hot exhaust gas) and 

converts it to usable heat. Waste heat 

process heaters are also referred to as 

recuperative process heaters. This 

definition includes both fired and 

unfired waste heat process heaters. 

* * * * * 

■ 28. Table 1 to subpart DDDDD of part 

63 is revised to read as follows: 

As stated in § 63.7500, you must 

comply with the following applicable 

emission limits: 

TABLE 1 TO SUBPART DDDDD OF PART 63—EMISSION LIMITS FOR NEW OR RECONSTRUCTED BOILERS AND PROCESS

HEATERS

[Units with heat input capacity of 10 million Btu per hour or greater] 

If your boiler or process heater 

is in this subcategory . . . 

For the following 

pollutants . . . 

The emissions must not exceed the following emission 

limits, except during startup 

and shutdown . . . 

Or the emissions must not 

exceed the following alternative output-based limits, except during startup and shutdown . . . Using this specified sampling 

volume or test run duration 

. . . 

1. Units in all subcategories 

designed to burn solid fuel. 

a. HCl ....................................... 2.2E–02 lb per MMBtu of heat 

input.

2.5E–02 lb per MMBtu of 

steam output or 0.28 lb per 

MWh.

For M26A, collect a minimum 

of 1 dscm per run; for M26 

collect a minimum of 120 liters per run. 

b. Mercury ................................ 8.0E–07 a lb per MMBtu of 

heat input.

8.7E–07 a lb per MMBtu of 

steam output or 1.1E–05 a lb 

per MWh.

For M29, collect a minimum of 

4 dscm per run; for M30A or 

M30B, collect a minimum 

sample as specified in the 

method; for ASTM D6784 b

collect a minimum of 4 

dscm. 

2. Units designed to burn coal/ 

solid fossil fuel.

a. Filterable PM (or TSM) ........ 1.1E–03 lb per MMBtu of heat 

input; or (2.3E–05 lb per 

MMBtu of heat input).

1.1E–03 lb per MMBtu of 

steam output or 1.4E–02 lb 

per MWh; or (2.7E–05 lb per 

MMBtu of steam output or 

2.9E–04 lb per MWh).

Collect a minimum of 3 dscm 

per run. 

3. Pulverized coal boilers designed to burn coal/solid fossil fuel.a. Carbon monoxide (CO) (or 

CEMS).

130 ppm by volume on a dry 

basis corrected to 3 percent 

oxygen, 3-run average; or 

(320 ppm by volume on a 

dry basis corrected to 3 percent oxygen, 30-day rolling 

average).

0.11 lb per MMBtu of steam 

output or 1.4 lb per MWh; 3- 

run average.

1 hr minimum sampling time. 

4. Stokers designed to burn 

coal/solid fossil fuel.

a. CO (or CEMS) ..................... 130 ppm by volume on a dry 

basis corrected to 3 percent 

oxygen, 3-run average; or 

(340 ppm by volume on a 

dry basis corrected to 3 percent oxygen, 30-day rolling 

average).

0.12 lb per MMBtu of steam 

output or 1.4 lb per MWh; 3- 

run average.

1 hr minimum sampling time. 

5. Fluidized bed units designed 

to burn coal/solid fossil fuel.

a. CO (or CEMS) ..................... 130 ppm by volume on a dry 

basis corrected to 3 percent 

oxygen, 3-run average; or 

(230 ppm by volume on a 

dry basis corrected to 3 percent oxygen, 30-day rolling 

average).

0.11 lb per MMBtu of steam 

output or 1.4 lb per MWh; 3- 

run average.

1 hr minimum sampling time. 

6. Fluidized bed units with an 

integrated heat exchanger 

designed to burn coal/solid 

fossil fuel.

a. CO (or CEMS) ..................... 140 ppm by volume on a dry 

basis corrected to 3 percent 

oxygen, 3-run average; or 

(150 ppm by volume on a 

dry basis corrected to 3 percent oxygen, 30-day rolling 

average).

1.2E–01 lb per MMBtu of 

steam output or 1.5 lb per 

MWh; 3-run average.

1 hr minimum sampling time. 

7. Stokers/sloped grate/others 

designed to burn wet biomass fuel.

a. CO (or CEMS) ..................... 620 ppm by volume on a dry 

basis corrected to 3 percent 

oxygen, 3-run average; or 

(390 ppm by volume on a 

dry basis corrected to 3 percent oxygen, 30-day rolling 

average).

5.8E–01 lb per MMBtu of 

steam output or 6.8 lb per 

MWh; 3-run average.

1 hr minimum sampling time. 

b. Filterable PM (or TSM) ........ 3.0E–02 lb per MMBtu of heat 

input; or (2.6E–05 lb per 

MMBtu of heat input).

3.5E–02 lb per MMBtu of 

steam output or 4.2E–01 lb 

per MWh; or (2.7E–05 lb per 

MMBtu of steam output or 

3.7E–04 lb per MWh).

Collect a minimum of 2 dscm 

per run. 


tkelley on DSK3SPTVN1PROD with 
7194 Federal Register / Vol. 78, No. 21 / Thursday, January 31, 2013 / Rules and Regulations 

TABLE 1 TO SUBPART DDDDD OF PART 63—EMISSION LIMITS FOR NEW OR RECONSTRUCTED BOILERS AND PROCESS

HEATERS—Continued 

[Units with heat input capacity of 10 million Btu per hour or greater] 

If your boiler or process heater 

is in this subcategory . . . 

For the following 

pollutants . . . 

The emissions must not exceed the following emission 

limits, except during startup 

and shutdown . . . 

Or the emissions must not 

exceed the following alternative output-based limits, except during startup and shutdown . . . Using this specified sampling 

volume or test run duration 

. . . 

8. Stokers/sloped grate/others 

designed to burn kiln-dried 

biomass fuel.

a. CO ....................................... 460 ppm by volume on a dry 

basis corrected to 3 percent 

oxygen.

4.2E–01 lb per MMBtu of 

steam output or 5.1 lb per 

MWh.

1 hr minimum sampling time. 

b. Filterable PM (or TSM) ........ 3.0E–02 lb per MMBtu of heat 

input; or (4.0E–03 lb per 

MMBtu of heat input).

3.5E–02 lb per MMBtu of 

steam output or 4.2E–01 lb 

per MWh; or (4.2E–03 lb per 

MMBtu of steam output or 

5.6E–02 lb per MWh).

Collect a minimum of 2 dscm 

per run. 

9. Fluidized bed units designed 

to burn biomass/bio-based 

solids.

a. CO (or CEMS) ..................... 230 ppm by volume on a dry 

basis corrected to 3 percent 

oxygen, 3-run average; or 

(310 ppm by volume on a 

dry basis corrected to 3 percent oxygen, 30-day rolling 

average).

2.2E–01 lb per MMBtu of 

steam output or 2.6 lb per 

MWh; 3-run average.

1 hr minimum sampling time. 

b. Filterable PM (or TSM) ........ 9.8E–03 lb per MMBtu of heat 

input; or (8.3E–05 a lb per 

MMBtu of heat input).

1.2E–02 lb per MMBtu of 

steam output or 0.14 lb per 

MWh; or (1.1E–04 a lb per 

MMBtu of steam output or 

1.2E–03 a lb per MWh).

Collect a minimum of 3 dscm 

per run. 

10. Suspension burners designed to burn biomass/biobased solids.a. CO (or CEMS) ..................... 2,400 ppm by volume on a dry 

basis corrected to 3 percent 

oxygen, 3-run average; or 

(2,000 ppm by volume on a 

dry basis corrected to 3 percent oxygen, 10-day rolling 

average).

1.9 lb per MMBtu of steam output or 27 lb per MWh; 3-run 

average.

1 hr minimum sampling time. 

b. Filterable PM (or TSM) ........ 3.0E–02 lb per MMBtu of heat 

input; or (6.5E–03 lb per 

MMBtu of heat input).

3.1E–02 lb per MMBtu of 

steam output or 4.2E–01 lb 

per MWh; or (6.6E–03 lb per 

MMBtu of steam output or 

9.1E–02 lb per MWh).

Collect a minimum of 2 dscm 

per run. 

11. Dutch Ovens/Pile burners 

designed to burn biomass/ 

bio-based solids.

a. CO (or CEMS) ..................... 330 ppm by volume on a dry 

basis corrected to 3 percent 

oxygen, 3-run average; or 

(520 ppm by volume on a 

dry basis corrected to 3 percent oxygen, 10-day rolling 

average).

3.5E–01 lb per MMBtu of 

steam output or 3.6 lb per 

MWh; 3-run average.

1 hr minimum sampling time. 

b. Filterable PM (or TSM) ........ 3.2E–03 lb per MMBtu of heat 

input; or (3.9E–05 lb per 

MMBtu of heat input).

4.3E–03 lb per MMBtu of 

steam output or 4.5E–02 lb 

per MWh; or (5.2E–05 lb per 

MMBtu of steam output or 

5.5E–04 lb per MWh).

Collect a minimum of 3 dscm 

per run. 

12. Fuel cell units designed to 

burn biomass/bio-based solids.

a. CO ....................................... 910 ppm by volume on a dry 

basis corrected to 3 percent 

oxygen.

1.1 lb per MMBtu of steam output or 1.0E+01 lb per MWh.1 hr minimum sampling time. 

b. Filterable PM (or TSM) ........ 2.0E–02 lb per MMBtu of heat 

input; or (2.9E–05 a lb per 

MMBtu of heat input).

3.0E–02 lb per MMBtu of 

steam output or 2.8E–01 lb 

per MWh; or (5.1E–05 lb per 

MMBtu of steam output or 

4.1E–04 lb per MWh).

Collect a minimum of 2 dscm 

per run. 

13. Hybrid suspension grate 

boiler designed to burn biomass/bio-based solids.

a. CO (or CEMS) ..................... 1,100 ppm by volume on a dry 

basis corrected to 3 percent 

oxygen, 3-run average; or 

(900 ppm by volume on a 

dry basis corrected to 3 percent oxygen, 30-day rolling 

average).

1.4 lb per MMBtu of steam output or 12 lb per MWh; 3-run 

average.

1 hr minimum sampling time. 

b. Filterable PM (or TSM) ........ 2.6E–02 lb per MMBtu of heat 

input; or (4.4E–04 lb per 

MMBtu of heat input).

3.3E–02 lb per MMBtu of 

steam output or 3.7E–01 lb 

per MWh; or (5.5E–04 lb per 

MMBtu of steam output or 

6.2E–03 lb per MWh).

Collect a minimum of 3 dscm 

per run. 

14. Units designed to burn liquid fuel.a. HCl ....................................... 4.4E–04 lb per MMBtu of heat 

input.

4.8E–04 lb per MMBtu of 

steam output or 6.1E–03 lb 

per MWh.

For M26A: Collect a minimum 

of 2 dscm per run; for M26, 

collect a minimum of 240 liters per run. 

b. Mercury ................................ 4.8E–07 a lb per MMBtu of 

heat input.

5.3E–07 a lb per MMBtu of 

steam output or 6.7E–06 a lb 

per MWh.

For M29, collect a minimum of 

4 dscm per run; for M30A or 

M30B, collect a minimum 

sample as specified in the 

method; for ASTM D6784 b

collect a minimum of 4 

dscm. 


tkelley on DSK3SPTVN1PROD with 
Federal Register / Vol. 78, No. 21 / Thursday, January 31, 2013 / Rules and Regulations 7195 

TABLE 1 TO SUBPART DDDDD OF PART 63—EMISSION LIMITS FOR NEW OR RECONSTRUCTED BOILERS AND PROCESS

HEATERS—Continued 

[Units with heat input capacity of 10 million Btu per hour or greater] 

If your boiler or process heater 

is in this subcategory . . . 

For the following 

pollutants . . . 

The emissions must not exceed the following emission 

limits, except during startup 

and shutdown . . . 

Or the emissions must not 

exceed the following alternative output-based limits, except during startup and shutdown . . . Using this specified sampling 

volume or test run duration 

. . . 

15. Units designed to burn 

heavy liquid fuel.

a. CO ....................................... 130 ppm by volume on a dry 

basis corrected to 3 percent 

oxygen, 3-run average.

0.13 lb per MMBtu of steam 

output or 1.4 lb per MWh; 3- 

run average.

1 hr minimum sampling time. 

b. Filterable PM (or TSM) ........ 1.3E–02 lb per MMBtu of heat 

input; or (7.5E–05 lb per 

MMBtu of heat input).

1.5E–02 lb per MMBtu of 

steam output or 1.8E–01 lb 

per MWh; or (8.2E–05 lb per 

MMBtu of steam output or 

1.1E–03 lb per MWh).

Collect a minimum of 3 dscm 

per run. 

16. Units designed to burn light 

liquid fuel.

a. CO ....................................... 130 ppm by volume on a dry 

basis corrected to 3 percent 

oxygen.

0.13 lb per MMBtu of steam 

output or 1.4 lb per MWh.

1 hr minimum sampling time. 

b. Filterable PM (or TSM) ........ 1.1E–03 a lb per MMBtu of 

heat input; or (2.9E–05 lb 

per MMBtu of heat input).

1.2E–03 a lb per MMBtu of 

steam output or 1.6E–02 a lb 

per MWh; or (3.2E–05 lb per 

MMBtu of steam output or 

4.0E–04 lb per MWh).

Collect a minimum of 3 dscm 

per run. 

17. Units designed to burn liquid fuel that are non-continental units.a. CO ....................................... 130 ppm by volume on a dry 

basis corrected to 3 percent 

oxygen, 3-run average 

based on stack test.

0.13 lb per MMBtu of steam 

output or 1.4 lb per MWh; 3- 

run average.

1 hr minimum sampling time. 

b. Filterable PM (or TSM) ........ 2.3E–02 lb per MMBtu of heat 

input; or (8.6E–04 lb per 

MMBtu of heat input).

2.5E–02 lb per MMBtu of 

steam output or 3.2E–01 lb 

per MWh; or (9.4E–04 lb per 

MMBtu of steam output or 

1.2E–02 lb per MWh).

Collect a minimum of 4 dscm 

per run. 

18. Units designed to burn gas 

2 (other) gases.

a. CO ....................................... 130 ppm by volume on a dry 

basis corrected to 3 percent 

oxygen.

0.16 lb per MMBtu of steam 

output or 1.0 lb per MWh.

1 hr minimum sampling time. 

b. HCl ....................................... 1.7E–03 lb per MMBtu of heat 

input.

2.9E–03 lb per MMBtu of 

steam output or 1.8E–02 lb 

per MWh.

For M26A, Collect a minimum 

of 2 dscm per run; for M26, 

collect a minimum of 240 liters per run. 

c. Mercury ................................ 7.9E–06 lb per MMBtu of heat 

input.

1.4E–05 lb per MMBtu of 

steam output or 8.3E–05 lb 

per MWh.

For M29, collect a minimum of 

3 dscm per run; for M30A or 

M30B, collect a minimum 

sample as specified in the 

method; for ASTM D6784 b

collect a minimum of 3 

dscm. 

d. Filterable PM (or TSM) ........ 6.7E–03 lb per MMBtu of heat 

input; or (2.1E–04 lb per 

MMBtu of heat input).

1.2E–02 lb per MMBtu of 

steam output or 7.0E–02 lb 

per MWh; or (3.5E–04 lb per 

MMBtu of steam output or 

2.2E–03 lb per MWh).

Collect a minimum of 3 dscm 

per run. 

a If you are conducting stack tests to demonstrate compliance and your performance tests for this pollutant for at least 2 consecutive years show that your emissions are at or below this limit, you can skip testing according to § 63.7515 if all of the other provisions of § 63.7515 are met. For all other pollutants that do not contain a footnote ‘‘a’’, your performance tests for this pollutant for at least 2 consecutive years must show that your emissions are at or below 75 percent of this limit in 

order to qualify for skip testing. b Incorporated by reference, see § 63.14. 

c If your affected source is a new or reconstructed affected source that commenced construction or reconstruction after June 4, 2010, and before January 31, 2013, 

you may comply with the emission limits in Tables 11, 12 or 13 to this subpart until January 31, 2016. On and after January 31, 2016, you must comply with the 

emission limits in Table 1 to this subpart. 

■ 29. Table 2 to subpart DDDDD of part 

63 is revised to read as follows: 

As stated in § 63.7500, you must 

comply with the following applicable 

emission limits: 

TABLE 2 TO SUBPART DDDDD OF PART 63—EMISSION LIMITS FOR EXISTING BOILERS AND PROCESS HEATERS

[Units with heat input capacity of 10 million Btu per hour or greater] 

If your boiler or process heater 

is in this subcategory . . . 

For the following 

pollutants . . . 

The emissions must not exceed the following emission 

limits, except during startup 

and shutdown . . . 

The emissions must not exceed the following alternative 

output-based limits, except 

during startup and 

shutdown . . . 

Using this specified sampling 

volume or test run 

duration . . . 

1. Units in all subcategories 

designed to burn solid fuel.

a. HCl ....................................... 2.2E–02 lb per MMBtu of heat 

input.

2.5E–02 lb per MMBtu of 

steam output or 0.27 lb per 

MWh.

For M26A, Collect a minimum 

of 1 dscm per run; for M26, 

collect a minimum of 120 liters per run. 


tkelley on DSK3SPTVN1PROD with 
7196 Federal Register / Vol. 78, No. 21 / Thursday, January 31, 2013 / Rules and Regulations 

TABLE 2 TO SUBPART DDDDD OF PART 63—EMISSION LIMITS FOR EXISTING BOILERS AND PROCESS HEATERS— 

Continued 

[Units with heat input capacity of 10 million Btu per hour or greater] 

If your boiler or process heater 

is in this subcategory . . . 

For the following 

pollutants . . . 

The emissions must not exceed the following emission 

limits, except during startup 

and shutdown . . . 

The emissions must not exceed the following alternative 

output-based limits, except 

during startup and 

shutdown . . . 

Using this specified sampling 

volume or test run 

duration . . . 

b. Mercury ................................ 5.7E–06 lb per MMBtu of heat 

input.

6.4E–06 lb per MMBtu of 

steam output or 7.3E–05 lb 

per MWh.

For M29, collect a minimum of 

3 dscm per run; for M30A or 

M30B, collect a minimum 

sample as specified in the 

method; for ASTM D6784 b

collect a minimum of 3 

dscm. 

2. Units design to burn coal/ 

solid fossil fuel.

a. Filterable PM (or TSM) ........ 4.0E–02 lb per MMBtu of heat 

input; or (5.3E–05 lb per 

MMBtu of heat input).

4.2E–02 lb per MMBtu of 

steam output or 4.9E–01 lb 

per MWh; or (5.6E–05 lb per 

MMBtu of steam output or 

6.5E–04 lb per MWh).

Collect a minimum of 2 dscm 

per run. 

3. Pulverized coal boilers designed to burn coal/solid fossil fuel.a. CO (or CEMS) ..................... 130 ppm by volume on a dry 

basis corrected to 3 percent 

oxygen, 3-run average; or 

(320 ppm by volume on a 

dry basis corrected to 3 percent oxygen, 30-day rolling 

average).

0.11 lb per MMBtu of steam 

output or 1.4 lb per MWh; 3- 

run average.

1 hr minimum sampling time. 

4. Stokers designed to burn 

coal/solid fossil fuel.

a. CO (or CEMS) ..................... 160 ppm by volume on a dry 

basis corrected to 3 percent 

oxygen, 3-run average; or 

(340 ppm by volume on a 

dry basis corrected to 3 percent oxygen, 30-day rolling 

average).

0.14 lb per MMBtu of steam 

output or 1.7 lb per MWh; 3- 

run average.

1 hr minimum sampling time. 

5. Fluidized bed units designed 

to burn coal/solid fossil fuel.

a. CO (or CEMS) ..................... 130 ppm by volume on a dry 

basis corrected to 3 percent 

oxygen, 3-run average; or 

(230 ppm by volume on a 

dry basis corrected to 3 percent oxygen, 30-day rolling 

average).

0.12 lb per MMBtu of steam 

output or 1.4 lb per MWh; 3- 

run average.

1 hr minimum sampling time. 

6. Fluidized bed units with an 

integrated heat exchanger 

designed to burn coal/solid 

fossil fuel.

a. CO (or CEMS) ..................... 140 ppm by volume on a dry 

basis corrected to 3 percent 

oxygen, 3-run average; or 

(150 ppm by volume on a 

dry basis corrected to 3 percent oxygen, 30-day rolling 

average).

1.3E–01 lb per MMBtu of 

steam output or 1.5 lb per 

MWh; 3-run average.

1 hr minimum sampling time. 

7. Stokers/sloped grate/others 

designed to burn wet biomass fuel.

a. CO (or CEMS) ..................... 1,500 ppm by volume on a dry 

basis corrected to 3 percent 

oxygen, 3-run average; or 

(720 ppm by volume on a 

dry basis corrected to 3 percent oxygen, 30-day rolling 

average).

1.4 lb per MMBtu of steam output or 17 lb per MWh; 3-run 

average.

1 hr minimum sampling time. 

b. Filterable PM (or TSM) ........ 3.7E–02 lb per MMBtu of heat 

input; or (2.4E–04 lb per 

MMBtu of heat input).

4.3E–02 lb per MMBtu of 

steam output or 5.2E–01 lb 

per MWh; or (2.8E–04 lb per 

MMBtu of steam output or 

3.4E–04 lb per MWh).

Collect a minimum of 2 dscm 

per run. 

8. Stokers/sloped grate/others 

designed to burn kiln-dried 

biomass fuel.

a. CO ....................................... 460 ppm by volume on a dry 

basis corrected to 3 percent 

oxygen.

4.2E–01 lb per MMBtu of 

steam output or 5.1 lb per 

MWh.

1 hr minimum sampling time. 

b. Filterable PM (or TSM) ........ 3.2E–01 lb per MMBtu of heat 

input; or (4.0E–03 lb per 

MMBtu of heat input).

3.7E–01 lb per MMBtu of 

steam output or 4.5 lb per 

MWh; or (4.6E–03 lb per 

MMBtu of steam output or 

5.6E–02 lb per MWh).

Collect a minimum of 1 dscm 

per run. 

9. Fluidized bed units designed 

to burn biomass/bio-based 

solid.

a. CO (or CEMS) ..................... 470 ppm by volume on a dry 

basis corrected to 3 percent 

oxygen, 3-run average; or 

(310 ppm by volume on a 

dry basis corrected to 3 percent oxygen, 30-day rolling 

average).

4.6E–01 lb per MMBtu of 

steam output or 5.2 lb per 

MWh; 3-run average.

1 hr minimum sampling time. 

b. Filterable PM (or TSM) ........ 1.1E–01 lb per MMBtu of heat 

input; or (1.2E–03 lb per 

MMBtu of heat input).

1.4E–01 lb per MMBtu of 

steam output or 1.6 lb per 

MWh; or (1.5E–03 lb per 

MMBtu of steam output or 

1.7E–02 lb per MWh).

Collect a minimum of 1 dscm 

per run. 


tkelley on DSK3SPTVN1PROD with 
Federal Register / Vol. 78, No. 21 / Thursday, January 31, 2013 / Rules and Regulations 7197 

TABLE 2 TO SUBPART DDDDD OF PART 63—EMISSION LIMITS FOR EXISTING BOILERS AND PROCESS HEATERS— 

Continued 

[Units with heat input capacity of 10 million Btu per hour or greater] 

If your boiler or process heater 

is in this subcategory . . . 

For the following 

pollutants . . . 

The emissions must not exceed the following emission 

limits, except during startup 

and shutdown . . . 

The emissions must not exceed the following alternative 

output-based limits, except 

during startup and 

shutdown . . . 

Using this specified sampling 

volume or test run 

duration . . . 

10. Suspension burners designed to burn biomass/biobased solid.a. CO (or CEMS) ..................... 2,400 ppm by volume on a dry 

basis corrected to 3 percent 

oxygen, 3-run average; or 

(2,000 ppm by volume on a 

dry basis corrected to 3 percent oxygen, 10-day rolling 

average).

1.9 lb per MMBtu of steam output or 27 lb per MWh; 3-run 

average.

1 hr minimum sampling time. 

b. Filterable PM (or TSM) ........ 5.1E–02 lb per MMBtu of heat 

input; or (6.5E–03 lb per 

MMBtu of heat input).

5.2E–02 lb per MMBtu of 

steam output or 7.1E–01 lb 

per MWh; or (6.6E–03 lb per 

MMBtu of steam output or 

9.1E–02 lb per MWh).

Collect a minimum of 2 dscm 

per run. 

11. Dutch Ovens/Pile burners 

designed to burn biomass/ 

bio-based solid.

a. CO (or CEMS) ..................... 770 ppm by volume on a dry 

basis corrected to 3 percent 

oxygen, 3-run average; or 

(520 ppm by volume on a 

dry basis corrected to 3 percent oxygen, 10-day rolling 

average).

8.4E–01 lb per MMBtu of 

steam output or 8.4 lb per 

MWh; 3-run average.

1 hr minimum sampling time. 

b. Filterable PM (or TSM) ........ 2.8E–01 lb per MMBtu of heat 

input; or (2.0E–03 lb per 

MMBtu of heat input).

3.9E–01 lb per MMBtu of 

steam output or 3.9 lb per 

MWh; or (2.8E–03 lb per 

MMBtu of steam output or 

2.8E–02 lb per MWh).

Collect a minimum of 1 dscm 

per run. 

12. Fuel cell units designed to 

burn biomass/bio-based 

solid.

a. CO ....................................... 1,100 ppm by volume on a dry 

basis corrected to 3 percent 

oxygen.

2.4 lb per MMBtu of steam output or 12 lb per MWh.1 hr minimum sampling time. 

b. Filterable PM (or TSM) ........ 2.0E–02 lb per MMBtu of heat 

input; or (5.8E–03 lb per 

MMBtu of heat input).

5.5E–02 lb per MMBtu of 

steam output or 2.8E–01 lb 

per MWh; or (1.6E–02 lb per 

MMBtu of steam output or 

8.1E–02 lb per MWh).

Collect a minimum of 2 dscm 

per run. 

13. Hybrid suspension grate 

units designed to burn biomass/bio-based solid.

a. CO (or CEMS) ..................... 2,800 ppm by volume on a dry 

basis corrected to 3 percent 

oxygen, 3-run average; or 

(900 ppm by volume on a 

dry basis corrected to 3 percent oxygen, 30-day rolling 

average).

2.8 lb per MMBtu of steam output or 31 lb per MWh; 3-run 

average.

1 hr minimum sampling time. 

b. Filterable PM (or TSM) ........ 4.4E–01 lb per MMBtu of heat 

input; or (4.5E–04 lb per 

MMBtu of heat input).

5.5E–01 lb per MMBtu of 

steam output or 6.2 lb per 

MWh; or (5.7E–04 lb per 

MMBtu of steam output or 

6.3E–03 lb per MWh).

Collect a minimum of 1 dscm 

per run. 

14. Units designed to burn liquid fuel.a. HCl ....................................... 1.1E–03 lb per MMBtu of heat 

input.

1.4E–03 lb per MMBtu of 

steam output or 1.6E–02 lb 

per MWh.

For M26A, collect a minimum 

of 2 dscm per run; for M26, 

collect a minimum of 240 liters per run. 

b. Mercury ................................ 2.0E–06 lb per MMBtu of heat 

input.

2.5E–06 lb per MMBtu of 

steam output or 2.8E–05 lb 

per MWh.

For M29, collect a minimum of 

3 dscm per run; for M30A or 

M30B collect a minimum 

sample as specified in the 

method, for ASTM D6784 b

collect a minimum of 2 

dscm. 

15. Units designed to burn 

heavy liquid fuel.

a. CO ....................................... 130 ppm by volume on a dry 

basis corrected to 3 percent 

oxygen, 3-run average.

0.13 lb per MMBtu of steam 

output or 1.4 lb per MWh; 3- 

run average.

1 hr minimum sampling time. 

b. Filterable PM (or TSM) ........ 6.2E–02 lb per MMBtu of heat 

input; or (2.0E–04 lb per 

MMBtu of heat input).

7.5E–02 lb per MMBtu of 

steam output or 8.6E–01 lb 

per MWh; or (2.5E–04 lb per 

MMBtu of steam output or 

2.8E–03 lb per MWh).

Collect a minimum of 1 dscm 

per run. 

16. Units designed to burn light 

liquid fuel.

a. CO ....................................... 130 ppm by volume on a dry 

basis corrected to 3 percent 

oxygen.

0.13 lb per MMBtu of steam 

output or 1.4 lb per MWh.

1 hr minimum sampling time. 

b. Filterable PM (or TSM) ........ 7.9E–03 lb per MMBtu of heat 

input; or (6.2E–05 lb per 

MMBtu of heat input).

9.6E–03 lb per MMBtu of 

steam output or 1.1E–01 lb 

per MWh; or (7.5E–05 lb per 

MMBtu of steam output or 

8.6E–04 lb per MWh).

Collect a minimum of 3 dscm 

per run. 

17. Units designed to burn liquid fuel that are non-continental units.a. CO ....................................... 130 ppm by volume on a dry 

basis corrected to 3 percent 

oxygen, 3-run average 

based on stack test.

0.13 lb per MMBtu of steam 

output or 1.4 lb per MWh; 3- 

run average.

1 hr minimum sampling time. 


tkelley on DSK3SPTVN1PROD with 
7198 Federal Register / Vol. 78, No. 21 / Thursday, January 31, 2013 / Rules and Regulations 

TABLE 2 TO SUBPART DDDDD OF PART 63—EMISSION LIMITS FOR EXISTING BOILERS AND PROCESS HEATERS— 

Continued 

[Units with heat input capacity of 10 million Btu per hour or greater] 

If your boiler or process heater 

is in this subcategory . . . 

For the following 

pollutants . . . 

The emissions must not exceed the following emission 

limits, except during startup 

and shutdown . . . 

The emissions must not exceed the following alternative 

output-based limits, except 

during startup and 

shutdown . . . 

Using this specified sampling 

volume or test run 

duration . . . 

b. Filterable PM (or TSM) ........ 2.7E–01 lb per MMBtu of heat 

input; or (8.6E–04 lb per 

MMBtu of heat input).

3.3E–01 lb per MMBtu of 

steam output or 3.8 lb per 

MWh; or (1.1E–03 lb per 

MMBtu of steam output or 

1.2E–02 lb per MWh).

Collect a minimum of 2 dscm 

per run. 

18. Units designed to burn gas 

2 (other) gases.

a. CO ....................................... 130 ppm by volume on a dry 

basis corrected to 3 percent 

oxygen.

0.16 lb per MMBtu of steam 

output or 1.0 lb per MWh.

1 hr minimum sampling time. 

b. HCl ....................................... 1.7E–03 lb per MMBtu of heat 

input.

2.9E–03 lb per MMBtu of 

steam output or 1.8E–02 lb 

per MWh.

For M26A, collect a minimum 

of 2 dscm per run; for M26, 

collect a minimum of 240 liters per run. 

c. Mercury ................................ 7.9E–06 lb per MMBtu of heat 

input.

1.4E–05 lb per MMBtu of 

steam output or 8.3E–05 lb 

per MWh.

For M29, collect a minimum of 

3 dscm per run; for M30A or 

M30B, collect a minimum 

sample as specified in the 

method; for ASTM D6784 b

collect a minimum of 2 

dscm. 

d. Filterable PM (or TSM) ........ 6.7E–03 lb per MMBtu of heat 

input or (2.1E–04 lb per 

MMBtu of heat input).

1.2E–02 lb per MMBtu of 

steam output or 7.0E–02 lb 

per MWh; or (3.5E–04 lb per 

MMBtu of steam output or 

2.2E–03 lb per MWh).

Collect a minimum of 3 dscm 

per run. 

a If you are conducting stack tests to demonstrate compliance and your performance tests for this pollutant for at least 2 consecutive years show that your emissions are at or below this limit, you can skip testing according to § 63.7515 if all of the other provisions of § 63.7515 are met. For all other pollutants that do not contain a footnote a, your performance tests for this pollutant for at least 2 consecutive years must show that your emissions are at or below 75 percent of this limit in 

order to qualify for skip testing. b Incorporated by reference, see § 63.14. 

■ 30. Table 3 to subpart DDDDD of part 

63 is revised to read as follows: 

As stated in § 63.7500, you must 

comply with the following applicable 

work practice standards: 

TABLE 3 TO SUBPART DDDDD OF PART 63—WORK PRACTICE STANDARDS

If your unit is . . . You must meet the following . . . 

1. A new or existing boiler or process heater with a continuous oxygen 

trim system that maintains an optimum air to fuel ratio, or a heat 

input capacity of less than or equal to 5 million Btu per hour in any of 

the following subcategories: unit designed to burn gas 1; unit designed to burn gas 2 (other); or unit designed to burn light liquid, or a 

limited use boiler or process heater.

Conduct a tune-up of the boiler or process heater every 5 years as 

specified in § 63.7540. 

2. A new or existing boiler or process heater without a continuous oxygen trim system and with heat input capacity of less than 10 million 

Btu per hour in the unit designed to burn heavy liquid or unit designed to burn solid fuel subcategories; or a new or existing boiler or 

process heater with heat input capacity of less than 10 million Btu 

per hour, but greater than 5 million Btu per hour, in any of the following subcategories: unit designed to burn gas 1; unit designed to 

burn gas 2 (other); or unit designed to burn light liquid.

Conduct a tune-up of the boiler or process heater biennially as specified in § 63.7540. 

3. A new or existing boiler or process heater without a continuous oxygen trim system and with heat input capacity of 10 million Btu per 

hour or greater.

Conduct a tune-up of the boiler or process heater annually as specified 

in § 63.7540. Units in either the Gas 1 or Metal Process Furnace 

subcategories will conduct this tune-up as a work practice for all regulated emissions under this subpart. Units in all other subcategories 

will conduct this tune-up as a work practice for dioxins/furans. 

4. An existing boiler or process heater located at a major source facility, not including limited use units.Must have a one-time energy assessment performed by a qualified energy assessor. An energy assessment completed on or after January 

1, 2008, that meets or is amended to meet the energy assessment 

requirements in this table, satisfies the energy assessment requirement. A facility that operates under an energy management program 

compatible with ISO 50001 that includes the affected units also satisfies the energy assessment requirement. The energy assessment 

must include the following with extent of the evaluation for items a. 

to e. appropriate for the on-site technical hours listed in § 63.7575: 

a. A visual inspection of the boiler or process heater system. 


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TABLE 3 TO SUBPART DDDDD OF PART 63—WORK PRACTICE STANDARDS—Continued 

If your unit is . . . You must meet the following . . . 

b. An evaluation of operating characteristics of the boiler or process 

heater systems, specifications of energy using systems, operating 

and maintenance procedures, and unusual operating constraints. 

c. An inventory of major energy use systems consuming energy from 

affected boilers and process heaters and which are under the control 

of the boiler/process heater owner/operator. 

d. A review of available architectural and engineering plans, facility operation and maintenance procedures and logs, and fuel usage. 

e. A review of the facility’s energy management practices and provide 

recommendations for improvements consistent with the definition of 

energy management practices, if identified. 

f. A list of cost-effective energy conservation measures that are within 

the facility’s control. 

g. A list of the energy savings potential of the energy conservation 

measures identified. 

h. A comprehensive report detailing the ways to improve efficiency, the 

cost of specific improvements, benefits, and the time frame for recouping those investments. 

5. An existing or new boiler or process heater subject to emission limits 

in Table 1 or 2 or 11 through 13 to this subpart during startup.

You must operate all CMS during startup. 

For startup of a boiler or process heater, you must use one or a combination of the following clean fuels: natural gas, synthetic natural 

gas, propane, distillate oil, syngas, ultra-low sulfur diesel, fuel oilsoaked rags, kerosene, hydrogen, paper, cardboard, refinery gas, 

and liquefied petroleum gas. 

If you start firing coal/solid fossil fuel, biomass/bio-based solids, heavy 

liquid fuel, or gas 2 (other) gases, you must vent emissions to the 

main stack(s) and engage all of the applicable control devices except 

limestone injection in fluidized bed combustion (FBC) boilers, dry 

scrubber, fabric filter, selective non-catalytic reduction (SNCR), and 

selective catalytic reduction (SCR). You must start your limestone injection in FBC boilers, dry scrubber, fabric filter, SNCR, and SCR 

systems as expeditiously as possible. Startup ends when steam or 

heat is supplied for any purpose. 

You must comply with all applicable emission limits at all times except 

for startup or shutdown periods conforming with this work practice. 

You must collect monitoring data during periods of startup, as specified in § 63.7535(b). You must keep records during periods of startup. You must provide reports concerning activities and periods of 

startup, as specified in § 63.7555. 

6. An existing or new boiler or process heater subject to emission limits 

in Tables 1 or 2 or 11 through 13 to this subpart during shutdown.

You must operate all CMS during shutdown. 

While firing coal/solid fossil fuel, biomass/bio-based solids, heavy liquid 

fuel, or gas 2 (other) gases during shutdown, you must vent emissions to the main stack(s) and operate all applicable control devices, 

except limestone injection in FBC boilers, dry scrubber, fabric filter, 

SNCR, and SCR. 

You must comply with all applicable emissions limits at all times except 

for startup or shutdown periods conforming with this work practice. 

You must collect monitoring data during periods of shutdown, as 

specified in § 63.7535(b). You must keep records during periods of 

shutdown. You must provide reports concerning activities and periods of shutdown, as specified in § 63.7555. 

■ 31. Table 4 to subpart DDDDD of part 

63 is revised to read as follows: 

As stated in § 63.7500, you must 

comply with the applicable operating 

limits: 

TABLE 4 TO SUBPART DDDDD OF PART 63—OPERATING LIMITS FOR BOILERS AND PROCESS HEATERS

When complying with a Table 1, 2, 11, 12, or 

13 numerical emission limit using . . . You must meet these operating limits . . . 

1. Wet PM scrubber control on a boiler not 

using a PM CPMS.

Maintain the 30-day rolling average pressure drop and the 30-day rolling average liquid flow 

rate at or above the lowest one-hour average pressure drop and the lowest one-hour average liquid flow rate, respectively, measured during the most recent performance test demonstrating compliance with the PM emission limitation according to § 63.7530(b) and Table 7 

to this subpart. 


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TABLE 4 TO SUBPART DDDDD OF PART 63—OPERATING LIMITS FOR BOILERS AND PROCESS HEATERS—Continued 

When complying with a Table 1, 2, 11, 12, or 

13 numerical emission limit using . . . You must meet these operating limits . . . 

2. Wet acid gas (HCl) scrubber control on a 

boiler not using a HCl CEMS.

Maintain the 30-day rolling average effluent pH at or above the lowest one-hour average pH 

and the 30-day rolling average liquid flow rate at or above the lowest one-hour average liquid flow rate measured during the most recent performance test demonstrating compliance 

with the HCl emission limitation according to § 63.7530(b) and Table 7 to this subpart. 

3. Fabric filter control on units not using a PM 

CPMS.

a. Maintain opacity to less than or equal to 10 percent opacity (daily block average); or 

b. Install and operate a bag leak detection system according to § 63.7525 and operate the fabric filter such that the bag leak detection system alert is not activated more than 5 percent of 

the operating time during each 6-month period. 

4. Electrostatic precipitator control on units not 

using a PM CPMS.

a. This option is for boilers and process heaters that operate dry control systems (i.e., an ESP 

without a wet scrubber). Existing and new boilers and process heaters must maintain opacity to less than or equal to 10 percent opacity (daily block average); or 

b. This option is only for boilers and process heaters not subject to PM CPMS or continuous 

compliance with an opacity limit (i.e., COMS). Maintain the 30-day rolling average total secondary electric power input of the electrostatic precipitator at or above the operating limits 

established during the performance test according to § 63.7530(b) and Table 7 to this subpart. 

5. Dry scrubber or carbon injection control on a 

boiler not using a mercury CEMS.

Maintain the minimum sorbent or carbon injection rate as defined in § 63.7575 of this subpart. 

6. Any other add-on air pollution control type on 

units not using a PM CPMS.

This option is for boilers and process heaters that operate dry control systems. Existing and 

new boilers and process heaters must maintain opacity to less than or equal to 10 percent 

opacity (daily block average). 

7. Fuel analysis ................................................... Maintain the fuel type or fuel mixture such that the applicable emission rates calculated according to § 63.7530(c)(1), (2) and/or (3) is less than the applicable emission limits. 

8. Performance testing ....................................... For boilers and process heaters that demonstrate compliance with a performance test, maintain the operating load of each unit such that it does not exceed 110 percent of the highest 

hourly average operating load recorded during the most recent performance test. 

9. Oxygen analyzer system ................................ For boilers and process heaters subject to a CO emission limit that demonstrate compliance 

with an O2 analyzer system as specified in § 63.7525(a), maintain the 30-day rolling average 

oxygen content at or above the lowest hourly average oxygen concentration measured during the most recent CO performance test, as specified in Table 8. This requirement does not 

apply to units that install an oxygen trim system since these units will set the trim system to 

the level specified in § 63.7525(a). 

10. SO2 CEMS .................................................... For boilers or process heaters subject to an HCl emission limit that demonstrate compliance 

with an SO2 CEMS, maintain the 30-day rolling average SO2 emission rate at or below the 

highest hourly average SO2 concentration measured during the most recent HCl performance test, as specified in Table 8. 

■ 32. Table 5 to subpart DDDDD of part 

63 is amended by: 

■ a. Revising the entry for ‘‘1. 

Particulate matter.’’ 

■ b. Remove the entry for ‘‘5. Dioxins/ 

Furans’’. 

■ c. Redesignating the entries for ‘‘2. 

Hydrogen chloride,’’ ‘‘3. Mercury,’’ and 

‘‘4. CO’’ as ‘‘3. Hydrogen chloride,’’ ‘‘4. 

Mercury,’’ and ‘‘5. CO,’’ respectively. 

■ d. Revising the newly redesignated 

entries for ‘‘4. Mercury’’ and ‘‘5. CO.’’ 

■ e. Add entry for ‘‘2. Total selected 

metals.’’ 

The revisions and addition read as 

follows: 

As stated in § 63.7520, you must 

comply with the following requirements 

for performance testing for existing, new 

or reconstructed affected sources: 

TABLE 5 TO SUBPART DDDDD OF PART 63—PERFORMANCE TESTING REQUIREMENTS

To conduct a performance test for the following pollutant . . . 

You must . . . Using . . . 

1. Filterable PM ......... a. Select sampling ports location and the number of traverse points.Method 1 at 40 CFR part 60, appendix A–1 of this chapter. 

b. Determine velocity and volumetric flow-rate 

of the stack gas.

Method 2, 2F, or 2G at 40 CFR part 60, appendix A–1 or A–2 to part 

60 of this chapter. 

c. Determine oxygen or carbon dioxide concentration of the stack gas.Method 3A or 3B at 40 CFR part 60, appendix A–2 to part 60 of this 

chapter, or ANSI/ASME PTC 19.10–1981.a

d. Measure the moisture content of the stack 

gas.

Method 4 at 40 CFR part 60, appendix A–3 of this chapter. 

e. Measure the PM emission concentration ..... Method 5 or 17 (positive pressure fabric filters must use Method 5D) 

at 40 CFR part 60, appendix A–3 or A–6 of this chapter. 

f. Convert emissions concentration to lb per 

MMBtu emission rates.

Method 19 F-factor methodology at 40 CFR part 60, appendix A–7 of 

this chapter. 

2. TSM ....................... a. Select sampling ports location and the number of traverse points.Method 1 at 40 CFR part 60, appendix A–1 of this chapter. 


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TABLE 5 TO SUBPART DDDDD OF PART 63—PERFORMANCE TESTING REQUIREMENTS—Continued 

To conduct a performance test for the following pollutant . . . 

You must . . . Using . . . 

b. Determine velocity and volumetric flow-rate 

of the stack gas.

Method 2, 2F, or 2G at 40 CFR part 60, appendix A–1 or A–2 of this 

chapter. 

c. Determine oxygen or carbon dioxide concentration of the stack gas.Method 3A or 3B at 40 CFR part 60, appendix A–1 of this chapter, or 

ANSI/ASME PTC 19.10–1981.a

d. Measure the moisture content of the stack 

gas.

Method 4 at 40 CFR part 60, appendix A–3 of this chapter. 

e. Measure the TSM emission concentration ... Method 29 at 40 CFR part 60, appendix A–8 of this chapter 

f. Convert emissions concentration to lb per 

MMBtu emission rates.

Method 19 F-factor methodology at 40 CFR part 60, appendix A–7 of 

this chapter. 

3. HCl ......................... a. Select sampling ports location and the number of traverse points.Method 1 at 40 CFR part 60, appendix A–1 of this chapter. 

b. Determine velocity and volumetric flow-rate 

of the stack gas.

Method 2, 2F, or 2G at 40 CFR part 60, appendix A–2 of this chapter. 

c. Determine oxygen or carbon dioxide concentration of the stack gas.Method 3A or 3B at 40 CFR part 60, appendix A–2 of this chapter, or 

ANSI/ASME PTC 19.10–1981.a

d. Measure the moisture content of the stack 

gas.

Method 4 at 40 CFR part 60, appendix A–3 of this chapter. 

e. Measure the HCl emission concentration ..... Method 26 or 26A (M26 or M26A) at 40 CFR part 60, appendix A–8 of 

this chapter. 

f. Convert emissions concentration to lb per 

MMBtu emission rates.

Method 19 F-factor methodology at 40 CFR part 60, appendix A–7 of 

this chapter. 

4. Mercury .................. a. Select sampling ports location and the number of traverse points.Method 1 at 40 CFR part 60, appendix A–1 of this chapter. 

b. Determine velocity and volumetric flow-rate 

of the stack gas.

Method 2, 2F, or 2G at 40 CFR part 60, appendix A–1 or A–2 of this 

chapter. 

c. Determine oxygen or carbon dioxide concentration of the stack gas.Method 3A or 3B at 40 CFR part 60, appendix A–1 of this chapter, or 

ANSI/ASME PTC 19.10–1981.a

d. Measure the moisture content of the stack 

gas.

Method 4 at 40 CFR part 60, appendix A–3 of this chapter. 

e. Measure the mercury emission concentration.Method 29, 30A, or 30B (M29, M30A, or M30B) at 40 CFR part 60, 

appendix A–8 of this chapter or Method 101A at 40 CFR part 61, 

appendix B of this chapter, or ASTM Method D6784.a

f. Convert emissions concentration to lb per 

MMBtu emission rates.

Method 19 F-factor methodology at 40 CFR part 60, appendix A–7 of 

this chapter. 

5. CO ......................... a. Select the sampling ports location and the 

number of traverse points.

Method 1 at 40 CFR part 60, appendix A–1 of this chapter. 

b. Determine oxygen concentration of the 

stack gas.

Method 3A or 3B at 40 CFR part 60, appendix A–3 of this chapter, or 

ASTM D6522–00 (Reapproved 2005), or ANSI/ASME PTC 19.10– 

1981.a

c. Measure the moisture content of the stack 

gas.

Method 4 at 40 CFR part 60, appendix A–3 of this chapter. 

d. Measure the CO emission concentration ..... Method 10 at 40 CFR part 60, appendix A–4 of this chapter. Use a 

measurement span value of 2 times the concentration of the applicable emission limit. 

* * * * * 

■ 33. Table 6 to subpart DDDDD of part 

63 is revised to read as follows: 

As stated in § 63.7521, you must 

comply with the following requirements 

for fuel analysis testing for existing, new 

or reconstructed affected sources. 

However, equivalent methods (as 

defined in § 63.7575) may be used in 

lieu of the prescribed methods at the 

discretion of the source owner or 

operator: 

TABLE 6 TO SUBPART DDDDD OF PART 63—FUEL ANALYSIS REQUIREMENTS

To conduct a fuel 

analysis for the following pollutant . . . You must . . . Using . . . 

1. Mercury .................. a. Collect fuel samples ...................................... Procedure in § 63.7521(c) or ASTM D5192 a, or ASTM D7430 a, or 

ASTM D6883 a, or ASTM D2234/D2234M a(for coal) or EPA 1631 or 

EPA 1631E or ASTM D6323 a (for solid), or EPA 821–R–01–013 

(for liquid or solid), or ASTM D4177 a (for liquid), or ASTM D4057 a

(for liquid), or equivalent. 

b. Composite fuel samples ................................ Procedure in § 63.7521(d) or equivalent. 

c. Prepare composited fuel samples ................. EPA SW–846–3050Ba (for solid samples), EPA SW–846–3020Aa (for 

liquid samples), ASTM D2013/D2013M a (for coal), ASTM D5198 a

(for biomass), or EPA 3050 a (for solid fuel), or EPA 821–R–01– 

013 a (for liquid or solid), or equivalent. 


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TABLE 6 TO SUBPART DDDDD OF PART 63—FUEL ANALYSIS REQUIREMENTS—Continued 

To conduct a fuel 

analysis for the following pollutant . . . You must . . . Using . . . 

d. Determine heat content of the fuel type ....... ASTM D5865 a (for coal) or ASTM E711 a (for biomass), or ASTM 

D5864 a for liquids and other solids, or ASTM D240 a or equivalent. 

e. Determine moisture content of the fuel type ASTM D3173 a, ASTM E871 a, or ASTM D5864 a, or ASTM D240, or 

ASTM D95 a (for liquid fuels), or ASTM D4006 a (for liquid fuels), or 

ASTM D4177 a (for liquid fuels) or ASTM D4057 a (for liquid fuels), 

or equivalent. 

f. Measure mercury concentration in fuel sample.ASTM D6722 a (for coal), EPA SW–846–7471Ba (for solid samples), 

or EPA SW–846–7470Aa (for liquid samples), or equivalent. 

g. Convert concentration into units of pounds 

of mercury per MMBtu of heat content.

Equation 8 in § 63.7530. 

h. Calculate the mercury emission rate from 

the boiler or process heater in units of 

pounds per million Btu.

Equations 10 and 12 in § 63.7530. 

2. HCl ......................... a. Collect fuel samples ...................................... Procedure in § 63.7521(c) or ASTM D5192 a, or ASTM D7430 a, or 

ASTM D6883 a, or ASTM D2234/D2234M a (for coal) or ASTM 

D6323 a (for coal or biomass), ASTM D4177 a (for liquid fuels) or 

ASTM D4057 a (for liquid fuels), or equivalent. 

b. Composite fuel samples ................................ Procedure in § 63.7521(d) or equivalent. 

c. Prepare composited fuel samples ................. EPA SW–846–3050Ba (for solid samples), EPA SW–846–3020Aa (for 

liquid samples), ASTM D2013/D2013M§a (for coal), or ASTM 

D5198§a (for biomass), or EPA 3050 a or equivalent. 

d. Determine heat content of the fuel type ....... ASTM D5865 a (for coal) or ASTM E711 a (for biomass), ASTM D5864, 

ASTM D240 a or equivalent. 

e. Determine moisture content of the fuel type ASTM D3173 a or ASTM E871 a, or D5864 a, or ASTM D240 a, or 

ASTM D95a (for liquid fuels), or ASTM D4006 a (for liquid fuels), or 

ASTM D4177 a (for liquid fuels) or ASTM D4057 a (for liquid fuels) or 

equivalent. 

f. Measure chlorine concentration in fuel sample.EPA SW–846–9250 a, ASTM D6721 a, ASTM D4208 a (for coal), or 

EPA SW–846–5050 a or ASTM E776 a (for solid fuel), or EPA SW– 

846–9056 a or SW–846–9076 a (for solids or liquids) or equivalent. 

g. Convert concentrations into units of pounds 

of HCl per MMBtu of heat content.

Equation 7 in § 63.7530. 

h. Calculate the HCl emission rate from the 

boiler or process heater in units of pounds 

per million Btu.

Equations 10 and 11 in § 63.7530. 

3. Mercury Fuel Specification for other 

gas 1 fuels.

a. Measure mercury concentration in the fuel 

sample and convert to units of micrograms 

per cubic meter.

Method 30B (M30B) at 40 CFR part 60, appendix A–8 of this chapter 

or ASTM D5954 a, ASTM D6350 a, ISO 6978–1:2003(E) a, or ISO 

6978–2:2003(E) a, or EPA–1631 a or equivalent. 

b. Measure mercury concentration in the exhaust gas when firing only the other gas 1 

fuel is fired in the boiler or process heater.

Method 29, 30A, or 30B (M29, M30A, or M30B) at 40 CFR part 60, 

appendix A–8 of this chapter or Method 101A or Method 102 at 40 

CFR part 61, appendix B of this chapter, or ASTM Method D6784 a

or equivalent. 

4. TSM for solid fuels a. Collect fuel samples ...................................... Procedure in § 63.7521(c) or ASTM D5192 a, or ASTM D7430 a, or 

ASTM D6883 a, or ASTM D2234/D2234M a (for coal) or ASTM 

D6323 a (for coal or biomass), or ASTM D4177 a,(for liquid fuels)or 

ASTM D4057 a (for liquid fuels),or equivalent. 

b. Composite fuel samples ................................ Procedure in § 63.7521(d) or equivalent. 

c. Prepare composited fuel samples ................. EPA SW–846–3050Ba (for solid samples), EPA SW–846–3020Aa (for 

liquid samples), ASTM D2013/D2013M a (for coal), ASTM D5198 a

or TAPPI T266 a (for biomass), or EPA 3050 a or equivalent. 

d. Determine heat content of the fuel type ....... ASTM D5865 a (for coal) or ASTM E711 a (for biomass), or ASTM 

D5864 a for liquids and other solids, or ASTM D240 a or equivalent. 

e. Determine moisture content of the fuel type ASTM D3173 a or ASTM E871 a, or D5864, or ASTM D240 a, or ASTM 

D95 a (for liquid fuels), or ASTM D4006a (for liquid fuels), or ASTM 

D4177 a (for liquid fuels) or ASTM D4057 a (for liquid fuels), or 

equivalent. 

f. Measure TSM concentration in fuel sample .. ASTM D3683 a, or ASTM D4606 a, or ASTM D6357 a or EPA 

200.8 a or EPA SW–846–6020 a, or EPA SW–846–6020Aa, or EPA 

SW–846–6010C a, EPA 7060 a or EPA 7060Aa (for arsenic only), or 

EPA SW–846–7740 a (for selenium only). 

g. Convert concentrations into units of pounds 

of TSM per MMBtu of heat content.

Equation 9 in § 63.7530. 

h. Calculate the TSM emission rate from the 

boiler or process heater in units of pounds 

per million Btu.

Equations 10 and 13 in § 63.7530. 

a Incorporated by reference, see § 63.14. 


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■ 34. Table 7 to subpart DDDDD of part 

63 is amended by: 

■ a. Revising the entry for ‘‘1. 

Particulate matter or mercury,’’. 

■ b. Revising the entry for ‘‘2. Hydrogen 

Chloride,’’. 

■ c. Revising the entry for ‘‘3. 

Mercury,’’. 

■ d. Revising the entry for ‘‘4. Carbon 

monoxide’’. 

The revisions read as follows: 

As stated in § 63.7520, you must 

comply with the following requirements 

for establishing operating limits: 

TABLE 7 TO SUBPART DDDDD OF PART 63—ESTABLISHING OPERATING LIMITS

If you have an applicable emission limit for . . . And your operating limits are 

based on . . . You must . . . Using . . . According to the following requirements 

1. PM, TSM, or mercury ........... a. Wet scrubber operating parameters.i. Establish a site-specific minimum scrubber pressure 

drop and minimum flow rate 

operating limit according to 

§ 63.7530(b).

(1) Data from the scrubber 

pressure drop and liquid flow 

rate monitors and the PM or 

mercury performance test.

(a) You must collect scrubber 

pressure drop and liquid flow 

rate data every 15 minutes 

during the entire period of 

the performance tests. 

(b) Determine the lowest hourly average scrubber pressure drop and liquid flow 

rate by computing the hourly 

averages using all of the 15- 

minute readings taken during each performance test. 

b. Electrostatic precipitator operating parameters (option 

only for units that operate 

wet scrubbers).

i. Establish a site-specific minimum total secondary electric power input according to 

§ 63.7530(b).

(1) Data from the voltage and 

secondary amperage monitors during the PM or mercury performance test.

(a) You must collect secondary 

voltage and secondary amperage for each ESP cell 

and calculate total secondary electric power input 

data every 15 minutes during the entire period of the 

performance tests. 

(b) Determine the average 

total secondary electric 

power input by computing 

the hourly averages using all 

of the 15-minute readings 

taken during each performance test. 

2. HCl ....................................... a. Wet scrubber operating parameters.i. Establish site-specific minimum pressure drop, effluent 

pH, and flow rate operating 

limits according to 

§ 63.7530(b).

(1) Data from the pressure 

drop, pH, and liquid flow-rate 

monitors and the HCl performance test.

(a) You must collect pH and 

liquid flow-rate data every 15 

minutes during the entire period of the performance 

tests. 

(b) Determine the hourly average pH and liquid flow rate 

by computing the hourly 

averages using all of the 15- 

minute readings taken during each performance test. 

b. Dry scrubber operating parameters.i. Establish a site-specific minimum sorbent injection rate 

operating limit according to 

§ 63.7530(b). If different acid 

gas sorbents are used during the HCl performance 

test, the average value for 

each sorbent becomes the 

site-specific operating limit 

for that sorbent.

(1) Data from the sorbent injection rate monitors and 

HCl or mercury performance 

test.

(a) You must collect sorbent 

injection rate data every 15 

minutes during the entire period of the performance 

tests. 

(b) Determine the hourly average sorbent injection rate by 

computing the hourly averages using all of the 15- 

minute readings taken during each performance test. 

(c) Determine the lowest hourly average of the three test 

run averages established 

during the performance test 

as your operating limit. 

When your unit operates at 

lower loads, multiply your 

sorbent injection rate by the 

load fraction (e.g., for 50 

percent load, multiply the injection rate operating limit by 

0.5) to determine the required injection rate. 

c. Alternative Maximum SO2

emission rate.

i. Establish a site-specific maximum SO2 emission rate operating limit according to 

§ 63.7530(b).

(1) Data from SO2 CEMS and 

the HCl performance test.

(a) You must collect the SO2

emissions data according to 

§ 63.7525(m) during the 

most recent HCl performance tests. 


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TABLE 7 TO SUBPART DDDDD OF PART 63—ESTABLISHING OPERATING LIMITS—Continued 

If you have an applicable emission limit for . . . And your operating limits are 

based on . . . You must . . . Using . . . According to the following requirements 

(b) The maximum SO2 emission rate is equal to the lowest hourly average SO2

emission rate measured during the most recent HCl performance tests. 

3. Mercury ................................ a. Activated carbon injection ... i. Establish a site-specific minimum activated carbon injection rate operating limit according to § 63.7530(b).(1) Data from the activated 

carbon rate monitors and 

mercury performance test.

(a) You must collect activated 

carbon injection rate data 

every 15 minutes during the 

entire period of the performance tests. 

(b) Determine the hourly average activated carbon injection rate by computing the 

hourly averages using all of 

the 15-minute readings 

taken during each performance test. 

(c) Determine the lowest hourly average established during the performance test as 

your operating limit. When 

your unit operates at lower 

loads, multiply your activated 

carbon injection rate by the 

load fraction (e.g., actual 

heat input divided by heat 

input during performance 

test, for 50 percent load, 

multiply the injection rate operating limit by 0.5) to determine the required injection 

rate. 

4. Carbon monoxide ................. a. Oxygen ................................ i. Establish a unit-specific limit 

for minimum oxygen level 

according to § 63.7520.

(1) Data from the oxygen analyzer system specified in 

§ 63.7525(a).

(a) You must collect oxygen 

data every 15 minutes during the entire period of the 

performance tests. 

(b) Determine the hourly average oxygen concentration by 

computing the hourly averages using all of the 15- 

minute readings taken during each performance test. 

(c) Determine the lowest hourly average established during the performance test as 

your minimum operating 

limit. 

* * * * * * * 

■ 35. Table 8 to subpart DDDDD of part 

63 is revised to read as follows: 

As stated in § 63.7540, you must show 

continuous compliance with the 

emission limitations for each boiler or 

process heater according to the 

following: 

TABLE 8 TO SUBPART DDDDD OF PART 63—DEMONSTRATING CONTINUOUS COMPLIANCE

If you must meet the following operating limits 

or work practice standards . . . You must demonstrate continuous compliance by . . . 

1. Opacity ............................................................ a. Collecting the opacity monitoring system data according to § 63.7525(c) and § 63.7535; and 

b. Reducing the opacity monitoring data to 6-minute averages; and 

c. Maintaining opacity to less than or equal to 10 percent (daily block average). 

2. PM CPMS ....................................................... a. Collecting the PM CPMS output data according to § 63.7525; 

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

c. Maintaining the 30-day rolling average PM CPMS output data to less than the operating 

limit established during the performance test according to § 63.7530(b)(4). 

3. Fabric Filter Bag Leak Detection Operation ... Installing and operating a bag leak detection system according to § 63.7525 and operating the 

fabric filter such that the requirements in § 63.7540(a)(9) are met. 

4. Wet Scrubber Pressure Drop and Liquid 

Flow-rate.

a. Collecting the pressure drop and liquid flow rate monitoring system data according to 

§§ 63.7525 and 63.7535; and 

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

c. Maintaining the 30-day rolling average pressure drop and liquid flow-rate at or above the 

operating limits established during the performance test according to § 63.7530(b). 

5. Wet Scrubber pH ............................................ a. Collecting the pH monitoring system data according to §§ 63.7525 and 63.7535; and 


tkelley on DSK3SPTVN1PROD with 
Federal Register / Vol. 78, No. 21 / Thursday, January 31, 2013 / Rules and Regulations 7205 

TABLE 8 TO SUBPART DDDDD OF PART 63—DEMONSTRATING CONTINUOUS COMPLIANCE—Continued 

If you must meet the following operating limits 

or work practice standards . . . You must demonstrate continuous compliance by . . . 

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

c. Maintaining the 30-day rolling average pH at or above the operating limit established during 

the performance test according to § 63.7530(b). 

6. Dry Scrubber Sorbent or Carbon Injection 

Rate.

a. Collecting the sorbent or carbon injection rate monitoring system data for the dry scrubber 

according to §§ 63.7525 and 63.7535; and 

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

c. Maintaining the 30-day rolling average sorbent or carbon injection rate at or above the minimum sorbent or carbon injection rate as defined in § 63.7575. 

7. Electrostatic Precipitator Total Secondary 

Electric Power Input.

a. Collecting the total secondary electric power input monitoring system data for the electrostatic precipitator according to §§ 63.7525 and 63.7535; and 

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

c. Maintaining the 30-day rolling average total secondary electric power input at or above the 

operating limits established during the performance test according to § 63.7530(b). 

8. Emission limits using fuel analysis ................. a. Conduct monthly fuel analysis for HCl or mercury or TSM according to Table 6 to this subpart; and 

b. Reduce the data to 12-month rolling averages; and 

c. Maintain the 12-month rolling average at or below the applicable emission limit for HCl or 

mercury or TSM in Tables 1 and 2 or 11 through 13 to this subpart. 

9. Oxygen content .............................................. a. Continuously monitor the oxygen content using an oxygen analyzer system according to 

§ 63.7525(a). This requirement does not apply to units that install an oxygen trim system 

since these units will set the trim system to the level specified in § 63.7525(a)(2). 

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

c. Maintain the 30-day rolling average oxygen content at or above the lowest hourly average 

oxygen level measured during the most recent CO performance test. 

10. Boiler or process heater operating load ....... a. Collecting operating load data or steam generation data every 15 minutes. 

b. Maintaining the operating load such that it does not exceed 110 percent of the highest hourly average operating load recorded during the most recent performance test according to 

§ 63.7520(c). 

11. SO2 emissions using SO2 CEMS ................. a. Collecting the SO2 CEMS output data according to § 63.7525; 

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

c. Maintaining the 30-day rolling average SO2 CEMS emission rate to a level at or below the 

minimum hourly SO2 rate measured during the most recent HCl performance test according 

to § 63.7530. 

■ 36. Table 9 to subpart DDDDD of part 

63 is amended by revising the entry for 

‘‘1. Compliance report’’ to read as 

follows: 

As stated in § 63.7550, you must 

comply with the following requirements 

for reports: 

TABLE 9 TO SUBPART DDDDD OF PART 63—REPORTING REQUIREMENTS

You must submit a(n) The report must contain . . . You must submit the report . . . 

1. Compliance report ..................... a. Information required in § 63.7550(c)(1) through 

(5); and 

Semiannually, annually, biennially, or every 5 years 

according to the requirements in § 63.7550(b). 

* * * * * * * 

■ 37. Table 10 to subpart DDDDD of part 

63 is amended by: 

■ a. Revising the entry for ‘‘§ 63.6(i)’’. 

■ b. Revising the entry for ‘‘§ 63.7(e)(1)’’. 

■ c. Revising the entry for ‘‘63.8(g)’’. 

■ d. Revising the entry for ‘‘§ 63.10(e) 

and (f)’’. 

■ e. Adding an entry for ‘‘§ 63.10(e)’’. 

The revisions and addition read as 

follows. 

As stated in § 63.7565, you must 

comply with the applicable General 

Provisions according to the following: 

TABLE 10 TO SUBPART DDDDD OF PART 63—APPLICABILITY OF GENERAL PROVISIONS TO SUBPART DDDDD 

Citation Subject Applies to subpart DDDDD 

*******

§ 63.6(i) ...................... Extension of compliance ................................... Yes. Note: Facilities may also request extensions of compliance for 

the installation of combined heat and power, waste heat recovery, 

or gas pipeline or fuel feeding infrastructure as a means of complying with this subpart. 


tkelley on DSK3SPTVN1PROD with 
7206 Federal Register / Vol. 78, No. 21 / Thursday, January 31, 2013 / Rules and Regulations 

TABLE 10 TO SUBPART DDDDD OF PART 63—APPLICABILITY OF GENERAL PROVISIONS TO SUBPART DDDDD— 

Continued 

Citation Subject Applies to subpart DDDDD 

*******

§ 63.7(e)(1) ................. Conditions for conducting performance tests ... No. Subpart DDDDD specifies conditions for conducting performance 

tests at § 63.7520(a) to (c). 

*******

§ 63.8(g) ..................... Reduction of monitoring data ............................ Yes. 

*******

§ 63.10(e) ................... Additional reporting requirements for sources 

with CMS.

Yes. 

§ 63.10(f) .................... Waiver of recordkeeping or reporting requirements.Yes. 

*******

■ 38. Add Table 11 to subpart DDDDD 

of part 63 to read as follows: 

TABLE 11 TO SUBPART DDDDD OF PART 63—ALTERNATIVE EMISSION LIMITS FOR NEW OR RECONSTRUCTED BOILERS

AND PROCESS HEATERS THAT COMMENCED CONSTRUCTION OR RECONSTRUCTION AFTER JUNE 4, 2010, AND BEFORE MAY 20, 2011 

If your boiler or process heater is in 

this subcategory . . . 

For the following pollutants . . . 

The emissions must not exceed the 

following emission limits, except during periods of startup and shutdown 

. . . 

Using this specified sampling volume 

or test run duration . . . 

1. Units in all subcategories designed 

to burn solid fuel.

a. HCl ........................ 0.022 lb per MMBtu of heat input ....... For M26A, collect a minimum of 1 

dscm per run; for M26 collect a 

minimum of 120 liters per run. 

2. Units in all subcategories designed 

to burn solid fuel that combust at 

least 10 percent biomass/bio-based 

solids on an annual heat input basis 

and less than 10 percent coal/solid 

fossil fuels on an annual heat input 

basis.

a. Mercury ................. 8.0E–07 a lb per MMBtu of heat input For M29, collect a minimum of 4 dscm 

per run; for M30A or M30B, collect 

a minimum sample as specified in 

the method; for ASTM D6784 b collect a minimum of 4 dscm. 

3. Units in all subcategories designed 

to burn solid fuel that combust at 

least 10 percent coal/solid fossil 

fuels on an annual heat input basis 

and less than 10 percent biomass/ 

bio-based solids on an annual heat 

input basis.

a. Mercury ................. 2.0E–06 lb per MMBtu of heat input ... For M29, collect a minimum of 4 dscm 

per run; for M30A or M30B, collect 

a minimum sample as specified in 

the method; for ASTM D6784 b collect a minimum of 4 dscm. 

4. Units designed to burn coal/solid 

fossil fuel.

a. Filterable PM (or 

TSM).

1.1E–03 lb per MMBtu of heat input; 

or (2.3E–05 lb per MMBtu of heat 

input).

Collect a minimum of 3 dscm per run. 

5. Pulverized coal boilers designed to 

burn coal/solid fossil fuel.

a. Carbon monoxide 

(CO) (or CEMS).

130 ppm by volume on a dry basis 

corrected to 3 percent oxygen, 3- 

run average; or (320 ppm by volume on a dry basis corrected to 3 

percent oxygen, 30-day rolling average).

1 hr minimum sampling time. 

6. Stokers designed to burn coal/solid 

fossil fuel.

a. CO (or CEMS) ....... 130 ppm by volume on a dry basis 

corrected to 3 percent oxygen, 3- 

run average; or (340 ppm by volume on a dry basis corrected to 3 

percent oxygen, 10-day rolling average).

1 hr minimum sampling time. 

7. Fluidized bed units designed to 

burn coal/solid fossil fuel.

a. CO (or CEMS) ....... 130 ppm by volume on a dry basis 

corrected to 3 percent oxygen, 3- 

run average; or (230 ppm by volume on a dry basis corrected to 3 

percent oxygen, 30-day rolling average).

1 hr minimum sampling time. 


tkelley on DSK3SPTVN1PROD with 
Federal Register / Vol. 78, No. 21 / Thursday, January 31, 2013 / Rules and Regulations 7207 

TABLE 11 TO SUBPART DDDDD OF PART 63—ALTERNATIVE EMISSION LIMITS FOR NEW OR RECONSTRUCTED BOILERS

AND PROCESS HEATERS THAT COMMENCED CONSTRUCTION OR RECONSTRUCTION AFTER JUNE 4, 2010, AND BEFORE MAY 20, 2011—Continued 

If your boiler or process heater is in 

this subcategory . . . 

For the following pollutants . . . 

The emissions must not exceed the 

following emission limits, except during periods of startup and shutdown 

. . . 

Using this specified sampling volume 

or test run duration . . . 

8. Fluidized bed units with an integrated heat exchanger designed to 

burn coal/solid fossil fuel.

a. CO (or CEMS) ....... 140 ppm by volume on a dry basis 

corrected to 3 percent oxygen, 3- 

run average; or (150 ppm by volume on a dry basis corrected to 3 

percent oxygen, 30-day rolling average).

1 hr minimum sampling time. 

9. Stokers/sloped grate/others designed to burn wet biomass fuel.a. CO (or CEMS) ....... 620 ppm by volume on a dry basis 

corrected to 3 percent oxygen, 3- 

run average; or (390 ppm by volume on a dry basis corrected to 3 

percent oxygen, 30-day rolling average).

1 hr minimum sampling time. 

b. Filterable PM (or 

TSM).

3.0E–02 lb per MMBtu of heat input; 

or (2.6E–05 lb per MMBtu of heat 

input).

Collect a minimum of 2 dscm per run. 

10. Stokers/sloped grate/others designed to burn kiln-dried biomass 

fuel.

a. CO ......................... 560 ppm by volume on a dry basis 

corrected to 3 percent oxygen.

1 hr minimum sampling time. 

b. Filterable PM (or 

TSM).

3.0E–02 lb per MMBtu of heat input; 

or (4.0E–03 lb per MMBtu of heat 

input).

Collect a minimum of 2 dscm per run. 

11. Fluidized bed units designed to 

burn biomass/bio-based solids.

a. CO (or CEMS) ....... 230 ppm by volume on a dry basis 

corrected to 3 percent oxygen, 3- 

run average; or (310 ppm by volume on a dry basis corrected to 3 

percent oxygen, 30-day rolling average).

1 hr minimum sampling time. 

b. Filterable PM (or 

TSM).

9.8E–03 lb per MMBtu of heat input; 

or (8.3E–05 a lb per MMBtu of heat 

input).

Collect a minimum of 3 dscm per run 

12. Suspension burners designed to 

burn biomass/bio-based solids.

a. CO (or CEMS) ....... 2,400 ppm by volume on a dry basis 

corrected to 3 percent oxygen, 3- 

run average; or (2,000 ppm by volume on a dry basis corrected to 3 

percent oxygen, 10-day rolling average).

1 hr minimum sampling time. 

b. Filterable PM (or 

TSM).

3.0E–02 lb per MMBtu of heat input; 

or (6.5E–03 lb per MMBtu of heat 

input).

Collect a minimum of 2 dscm per run. 

13. Dutch Ovens/Pile burners designed to burn biomass/bio-based 

solids.

a. CO (or CEMS) ....... 1,010 ppm by volume on a dry basis 

corrected to 3 percent oxygen, 3- 

run average; or (520 ppm by volume on a dry basis corrected to 3 

percent oxygen, 10-day rolling average).

1 hr minimum sampling time. 

b. Filterable PM (or 

TSM).

8.0E–03 lb per MMBtu of heat input; 

or (3.9E–05 lb per MMBtu of heat 

input).

Collect a minimum of 3 dscm per run. 

14. Fuel cell units designed to burn 

biomass/bio-based solids.

a. CO ......................... 910 ppm by volume on a dry basis 

corrected to 3 percent oxygen.

1 hr minimum sampling time. 

b. Filterable PM (or 

TSM).

2.0E–02 lb per MMBtu of heat input; 

or (2.9E–05 lb per MMBtu of heat 

input).

Collect a minimum of 2 dscm per run. 

15. Hybrid suspension grate boiler designed to burn biomass/bio-based 

solids.

a. CO (or CEMS) ....... 1,100 ppm by volume on a dry basis 

corrected to 3 percent oxygen, 3- 

run average; or (900 ppm by volume on a dry basis corrected to 3 

percent oxygen, 30-day rolling average).

1 hr minimum sampling time. 

b. Filterable PM (or 

TSM).

2.6E–02 lb per MMBtu of heat input; 

or (4.4E–04 lb per MMBtu of heat 

input).

Collect a minimum of 3 dscm per run. 

16. Units designed to burn liquid fuel .. a. HCl ........................ 4.4E–04 lb per MMBtu of heat input ... For M26A: Collect a minimum of 2 

dscm per run; for M26, collect a 

minimum of 240 liters per run. 


tkelley on DSK3SPTVN1PROD with 
7208 Federal Register / Vol. 78, No. 21 / Thursday, January 31, 2013 / Rules and Regulations 

TABLE 11 TO SUBPART DDDDD OF PART 63—ALTERNATIVE EMISSION LIMITS FOR NEW OR RECONSTRUCTED BOILERS

AND PROCESS HEATERS THAT COMMENCED CONSTRUCTION OR RECONSTRUCTION AFTER JUNE 4, 2010, AND BEFORE MAY 20, 2011—Continued 

If your boiler or process heater is in 

this subcategory . . . 

For the following pollutants . . . 

The emissions must not exceed the 

following emission limits, except during periods of startup and shutdown 

. . . 

Using this specified sampling volume 

or test run duration . . . 

b. Mercury ................. 4.8E–07 a lb per MMBtu of heat input For M29, collect a minimum of 4 dscm 

per run; for M30A or M30B, collect 

a minimum sample as specified in 

the method; for ASTM D6784 b collect a minimum of 4 dscm. 

17. Units designed to burn heavy liquid fuel.a. CO ......................... 130 ppm by volume on a dry basis 

corrected to 3 percent oxygen, 3- 

run average.

1 hr minimum sampling time. 

b. Filterable PM (or 

TSM).

1.3E–02 lb per MMBtu of heat input; 

or (7.5E–05 lb per MMBtu of heat 

input).

Collect a minimum of 3 dscm per run. 

18. Units designed to burn light liquid 

fuel.

a. CO ......................... 130 ppm by volume on a dry basis 

corrected to 3 percent oxygen.

1 hr minimum sampling time. 

b. Filterable PM (or 

TSM).

2.0E–03 a lb per MMBtu of heat input; 

or (2.9E–05 lb per MMBtu of heat 

input).

Collect a minimum of 3 dscm per run 

19. Units designed to burn liquid fuel 

that are non-continental units.

a. CO ......................... 130 ppm by volume on a dry basis 

corrected to 3 percent oxygen, 3- 

run average based on stack test.

1 hr minimum sampling time. 

b. Filterable PM (or 

TSM).

2.3E–02 lb per MMBtu of heat input; 

or (8.6E–04 lb per MMBtu of heat 

input).

Collect a minimum of 4 dscm per run 

20. Units designed to burn gas 2 

(other) gases.

a. CO ......................... 130 ppm by volume on a dry basis 

corrected to 3 percent oxygen.

1 hr minimum sampling time. 

b. HCl ........................ 1.7E–03 lb per MMBtu of heat input ... For M26A, collect a minimum of 2 

dscm per run; for M26, collect a 

minimum of 240 liters per run. 

c. Mercury .................. 7.9E–06 lb per MMBtu of heat input ... For M29, collect a minimum of 3 dscm 

per run; for M30A or M30B, collect 

a minimum sample as specified in 

the method; for ASTM D6784 b collect a minimum of 3 dscm. 

d. Filterable PM (or 

TSM).

6.7E–03 lb per MMBtu of heat input; 

or (2.1E–04 lb per MMBtu of heat 

input).

Collect a minimum of 3 dscm per run 

a If you are conducting stack tests to demonstrate compliance and your performance tests for this pollutant for at least 2 consecutive years 

show that your emissions are at or below this limit, you can skip testing according to § 63.7515 if all of the other provisions of § 63.7515 are met. 

For all other pollutants that do not contain a footnote ‘‘a’’, your performance tests for this pollutant for at least 2 consecutive years must show 

that your emissions are at or below 75 percent of this limit in order to qualify for skip testing. b Incorporated by reference, see § 63.14. 

■ 39. Add Table 12 to subpart DDDDD 

of part 63 to read as follows: 

TABLE 12 TO SUBPART DDDDD OF PART 63—ALTERNATIVE EMISSION LIMITS FOR NEW OR RECONSTRUCTED BOILERS

AND PROCESS HEATERS THAT COMMENCED CONSTRUCTION OR RECONSTRUCTION AFTER MAY 20, 2011, AND BEFORE DECEMBER 23, 2011 

If your boiler or process heater is in 

this subcategory . . . 

For the following pollutants . . . 

The emissions must not exceed the 

following emission limits, except during periods of startup and shutdown 

. . . 

Using this specified sampling volume 

or test run duration . . . 

1. Units in all subcategories designed 

to burn solid fuel.

a. HCl ........................ 0.022 lb per MMBtu of heat input ....... For M26A, collect a minimum of 1 

dscm per run; for M26 collect a 

minimum of 120 liters per run. 

b. Mercury ................. 3.5E–06 a lb per MMBtu of heat input For M29, collect a minimum of 3 dscm 

per run; for M30A or M30B, collect 

a minimum sample as specified in 

the method; for ASTM D6784 b collect a minimum of 3 dscm. 

2. Units design to burn coal/solid fossil 

fuel.

a. Filterable PM (or 

TSM).

1.1E–03 lb per MMBtu of heat input; 

or (2.3E–05 lb per MMBtu of heat 

input).

Collect a minimum of 3 dscm per run. 


tkelley on DSK3SPTVN1PROD with 
Federal Register / Vol. 78, No. 21 / Thursday, January 31, 2013 / Rules and Regulations 7209 

TABLE 12 TO SUBPART DDDDD OF PART 63—ALTERNATIVE EMISSION LIMITS FOR NEW OR RECONSTRUCTED BOILERS

AND PROCESS HEATERS THAT COMMENCED CONSTRUCTION OR RECONSTRUCTION AFTER MAY 20, 2011, AND BEFORE DECEMBER 23, 2011—Continued 

If your boiler or process heater is in 

this subcategory . . . 

For the following pollutants . . . 

The emissions must not exceed the 

following emission limits, except during periods of startup and shutdown 

. . . 

Using this specified sampling volume 

or test run duration . . . 

3. Pulverized coal boilers designed to 

burn coal/solid fossil fuel.

a. Carbon monoxide 

(CO) (or CEMS).

130 ppm by volume on a dry basis 

corrected to 3 percent oxygen, 3- 

run average; or (320 ppm by volume on a dry basis corrected to 3 

percent oxygen, 30-day rolling average).

1 hr minimum sampling time. 

4. Stokers designed to burn coal/solid 

fossil fuel.

a. CO (or CEMS) ....... 130 ppm by volume on a dry basis 

corrected to 3 percent oxygen, 3- 

run average; or (340 ppm by volume on a dry basis corrected to 3 

percent oxygen, 10-day rolling average).

1 hr minimum sampling time. 

5. Fluidized bed units designed to 

burn coal/solid fossil fuel.

a. CO (or CEMS) ....... 130 ppm by volume on a dry basis 

corrected to 3 percent oxygen, 3- 

run average; or (230 ppm by volume on a dry basis corrected to 3 

percent oxygen, 30-day rolling average).

1 hr minimum sampling time. 

6. Fluidized bed units with an integrated heat exchanger designed to 

burn coal/solid fossil fuel.

a. CO (or CEMS) ....... 140 ppm by volume on a dry basis 

corrected to 3 percent oxygen, 3- 

run average; or (150 ppm by volume on a dry basis corrected to 3 

percent oxygen, 30-day rolling average).

1 hr minimum sampling time. 

7. Stokers/sloped grate/others designed to burn wet biomass fuel.a. CO (or CEMS) ....... 620 ppm by volume on a dry basis 

corrected to 3 percent oxygen, 3- 

run average; or (390 ppm by volume on a dry basis corrected to 3 

percent oxygen, 30-day rolling average).

1 hr minimum sampling time. 

b. Filterable PM (or 

TSM).

3.0E–02 lb per MMBtu of heat input; 

or (2.6E–05 lb per MMBtu of heat 

input).

Collect a minimum of 2 dscm per run. 

8. Stokers/sloped grate/others designed to burn kiln-dried biomass 

fuel.

a. CO ......................... 460 ppm by volume on a dry basis 

corrected to 3 percent oxygen.

1 hr minimum sampling time. 

b. Filterable PM (or 

TSM).

3.0E–02 lb per MMBtu of heat input; 

or (4.0E–03 lb per MMBtu of heat 

input).

Collect a minimum of 2 dscm per run. 

9. Fluidized bed units designed to 

burn biomass/bio-based solids.

a. CO (or CEMS) ....... 260 ppm by volume on a dry basis 

corrected to 3 percent oxygen, 3- 

run average; or (310 ppm by volume on a dry basis corrected to 3 

percent oxygen, 30-day rolling average).

1 hr minimum sampling time. 

b. Filterable PM (or 

TSM).

9.8E–03 lb per MMBtu of heat input; 

or (8.3E–05 a lb per MMBtu of heat 

input).

Collect a minimum of 3 dscm per run. 

10. Suspension burners designed to 

burn biomass/bio-based solids.

a. CO (or CEMS) ....... 2,400 ppm by volume on a dry basis 

corrected to 3 percent oxygen, 3- 

run average; or (2,000 ppm by volume on a dry basis corrected to 3 

percent oxygen, 10-day rolling average).

1 hr minimum sampling time. 

b. Filterable PM (or 

TSM).

3.0E–02 lb per MMBtu of heat input; 

or (6.5E–03 lb per MMBtu of heat 

input).

Collect a minimum of 2 dscm per run. 

11. Dutch Ovens/Pile burners designed to burn biomass/bio-based 

solids.

a. CO (or CEMS) ....... 470 ppm by volume on a dry basis 

corrected to 3 percent oxygen, 3- 

run average; or (520 ppm by volume on a dry basis corrected to 3 

percent oxygen, 10-day rolling average).

1 hr minimum sampling time. 

b. Filterable PM (or 

TSM).

3.2E–03 lb per MMBtu of heat input; 

or (3.9E–05 lb per MMBtu of heat 

input).

Collect a minimum of 3 dscm per run. 


tkelley on DSK3SPTVN1PROD with 
7210 Federal Register / Vol. 78, No. 21 / Thursday, January 31, 2013 / Rules and Regulations 

TABLE 12 TO SUBPART DDDDD OF PART 63—ALTERNATIVE EMISSION LIMITS FOR NEW OR RECONSTRUCTED BOILERS

AND PROCESS HEATERS THAT COMMENCED CONSTRUCTION OR RECONSTRUCTION AFTER MAY 20, 2011, AND BEFORE DECEMBER 23, 2011—Continued 

If your boiler or process heater is in 

this subcategory . . . 

For the following pollutants . . . 

The emissions must not exceed the 

following emission limits, except during periods of startup and shutdown 

. . . 

Using this specified sampling volume 

or test run duration . . . 

12. Fuel cell units designed to burn 

biomass/bio-based solids.

a. CO ......................... 910 ppm by volume on a dry basis 

corrected to 3 percent oxygen.

1 hr minimum sampling time. 

b. Filterable PM (or 

TSM).

2.0E–02 lb per MMBtu of heat input; 

or (2.9E–05 lb per MMBtu of heat 

input).

Collect a minimum of 2 dscm per run. 

13. Hybrid suspension grate boiler designed to burn biomass/bio-based 

solids.

a. CO (or CEMS) ....... 1,500 ppm by volume on a dry basis 

corrected to 3 percent oxygen, 3- 

run average; or (900 ppm by volume on a dry basis corrected to 3 

percent oxygen, 30-day rolling average).

1 hr minimum sampling time. 

b. Filterable PM (or 

TSM).

2.6E–02 lb per MMBtu of heat input; 

or (4.4E–04 lb per MMBtu of heat 

input).

Collect a minimum of 3 dscm per run. 

14. Units designed to burn liquid fuel .. a. HCl ........................ 4.4E–04 lb per MMBtu of heat input ... For M26A: Collect a minimum of 2 

dscm per run; for M26, collect a 

minimum of 240 liters per run. 

b. Mercury ................. 4.8E–07 a lb per MMBtu of heat input For M29, collect a minimum of 4 dscm 

per run; for M30A or M30B, collect 

a minimum sample as specified in 

the method; for ASTM D6784 b collect a minimum of 4 dscm. 

15. Units designed to burn heavy liquid fuel.a. CO ......................... 130 ppm by volume on a dry basis 

corrected to 3 percent oxygen, 3- 

run average.

1 hr minimum sampling time. 

b. Filterable PM (or 

TSM).

1.3E–02 lb per MMBtu of heat input; 

or (7.5E–05 lb per MMBtu of heat 

input).

Collect a minimum of 2 dscm per run. 

16. Units designed to burn light liquid 

fuel.

a. CO ......................... 130 ppm by volume on a dry basis 

corrected to 3 percent oxygen.

1 hr minimum sampling time. 

b. Filterable PM (or 

TSM).

1.3E–03 a lb per MMBtu of heat input; 

or (2.9E–05 lb per MMBtu of heat 

input).

Collect a minimum of 3 dscm per run. 

17. Units designed to burn liquid fuel 

that are non-continental units.

a. CO ......................... 130 ppm by volume on a dry basis 

corrected to 3 percent oxygen, 3- 

run average based on stack test.

1 hr minimum sampling time. 

b. Filterable PM (or 

TSM).

2.3E–02 lb per MMBtu of heat input; 

or (8.6E–04 lb per MMBtu of heat 

input).

Collect a minimum of 4 dscm per run. 

18. Units designed to burn gas 2 

(other) gases.

a. CO ......................... 130 ppm by volume on a dry basis 

corrected to 3 percent oxygen.

1 hr minimum sampling time. 

b. HCl ........................ 1.7E–03 lb per MMBtu of heat input ... For M26A, Collect a minimum of 2 

dscm per run; for M26, collect a 

minimum of 240 liters per run. 

c. Mercury .................. 7.9E–06 lb per MMBtu of heat input ... For M29, collect a minimum of 3 dscm 

per run; for M30A or M30B, collect 

a minimum sample as specified in 

the method; for ASTM D6784 b collect a minimum of 3 dscm. 

d. Filterable PM (or 

TSM).

6.7E–03 lb per MMBtu of heat input; 

or (2.1E–04 lb per MMBtu of heat 

input).

Collect a minimum of 3 dscm per run. 

a If you are conducting stack tests to demonstrate compliance and your performance tests for this pollutant for at least 2 consecutive years 

show that your emissions are at or below this limit, you can skip testing according to § 63.7515 if all of the other provision of § 63.7515 are met. 

For all other pollutants that do not contain a footnote ‘‘a’’, your performance tests for this pollutant for at least 2 consecutive years must show 

that your emissions are at or below 75 percent of this limit in order to qualify for skip testing. b Incorporated by reference, see § 63.14. 

■ 40. Add Table 13 to subpart DDDDD 

of part 63 to read as follows: 


tkelley on DSK3SPTVN1PROD with 
Federal Register / Vol. 78, No. 21 / Thursday, January 31, 2013 / Rules and Regulations 7211 

TABLE 13 TO SUBPART DDDDD OF PART 63—ALTERNATIVE EMISSION LIMITS FOR NEW OR RECONSTRUCTED BOILERS

AND PROCESS HEATERS THAT COMMENCED CONSTRUCTION OR RECONSTRUCTION AFTER DECEMBER 23, 2011, AND

BEFORE JANUARY 31, 2013 

If your boiler or process heater is in 

this subcategory . . . 

For the following pollutants . . . 

The emissions must not exceed the 

following emission limits, except during periods of startup and shutdown 

. . . 

Using this specified sampling volume 

or test run duration . . . 

1. Units in all subcategories designed 

to burn solid fuel.

a. HCl ........................ 0.022 lb per MMBtu of heat input ....... For M26A, collect a minimum of 1 

dscm per run; for M26 collect a 

minimum of 120 liters per run. 

b. Mercury ................. 8.6E–07 a lb per MMBtu of heat input For M29, collect a minimum of 4 dscm 

per run; for M30A or M30B, collect 

a minimum sample as specified in 

the method; for ASTM D6784 b collect a minimum of 4 dscm. 

2. Pulverized coal boilers designed to 

burn coal/solid fossil fuel.

a. Carbon monoxide 

(CO) (or CEMS).

130 ppm by volume on a dry basis 

corrected to 3 percent oxygen, 3- 

run average; or (320 ppm by volume on a dry basis corrected to 3 

percent oxygen, 30-day rolling average).

1 hr minimum sampling time. 

b. Filterable PM (or 

TSM).

1.1E–03 lb per MMBtu of heat input; 

or (2.8E–05 lb per MMBtu of heat 

input).

Collect a minimum of 3 dscm per run. 

3. Stokers designed to burn coal/solid 

fossil fuel.

a. CO (or CEMS) ....... 130 ppm by volume on a dry basis 

corrected to 3 percent oxygen, 3- 

run average; or (340 ppm by volume on a dry basis corrected to 3 

percent oxygen, 10-day rolling average).

1 hr minimum sampling time. 

b. Filterable PM (or 

TSM).

2.8E–02 lb per MMBtu of heat input; 

or (2.3E–05 lb per MMBtu of heat 

input).

Collect a minimum of 2 dscm per run. 

4. Fluidized bed units designed to 

burn coal/solid fossil fuel.

a. CO (or CEMS) ....... 130 ppm by volume on a dry basis 

corrected to 3 percent oxygen, 3- 

run average; or (230 ppm by volume on a dry basis corrected to 3 

percent oxygen, 30-day rolling average).

1 hr minimum sampling time. 

b. Filterable PM (or 

TSM).

1.1E–03 lb per MMBtu of heat input; 

or (2.3E–05 lb per MMBtu of heat 

input).

Collect a minimum of 3 dscm per run. 

5. Fluidized bed units with an integrated heat exchanger designed to 

burn coal/solid fossil fuel.

a. CO (or CEMS) ....... 140 ppm by volume on a dry basis 

corrected to 3 percent oxygen, 3- 

run average; or (150 ppm by volume on a dry basis corrected to 3 

percent oxygen, 30-day rolling average).

1 hr minimum sampling time. 

b. Filterable PM (or 

TSM).

1.1E–03 lb per MMBtu of heat input; 

or (2.3E–05 lb per MMBtu of heat 

input).

Collect a minimum of 3 dscm per run. 

6. Stokers/sloped grate/others designed to burn wet biomass fuel.a. CO (or CEMS) ....... 620 ppm by volume on a dry basis 

corrected to 3 percent oxygen, 3- 

run average; or (410 ppm by volume on a dry basis corrected to 3 

percent oxygen, 10-day rolling average).

1 hr minimum sampling time. 

b. Filterable PM (or 

TSM).

3.0E–02 lb per MMBtu of heat input; 

or (2.6E–05 lb per MMBtu of heat 

input).

Collect a minimum of 2 dscm per run. 

7. Stokers/sloped grate/others designed to burn kiln-dried biomass 

fuel.

a. CO ......................... 460 ppm by volume on a dry basis 

corrected to 3 percent oxygen.

1 hr minimum sampling time. 

b. Filterable PM (or 

TSM).

3.2E–01 lb per MMBtu of heat input; 

or (4.0E–03 lb per MMBtu of heat 

input).

Collect a minimum of 2 dscm per run. 

8. Fluidized bed units designed to 

burn biomass/bio-based solids.

a. CO (or CEMS) ....... 230 ppm by volume on a dry basis 

corrected to 3 percent oxygen, 3- 

run average; or (310 ppm by volume on a dry basis corrected to 3 

percent oxygen, 30-day rolling average).

1 hr minimum sampling time. 


tkelley on DSK3SPTVN1PROD with 
7212 Federal Register / Vol. 78, No. 21 / Thursday, January 31, 2013 / Rules and Regulations 

TABLE 13 TO SUBPART DDDDD OF PART 63—ALTERNATIVE EMISSION LIMITS FOR NEW OR RECONSTRUCTED BOILERS

AND PROCESS HEATERS THAT COMMENCED CONSTRUCTION OR RECONSTRUCTION AFTER DECEMBER 23, 2011, AND

BEFORE JANUARY 31, 2013—Continued 

If your boiler or process heater is in 

this subcategory . . . 

For the following pollutants . . . 

The emissions must not exceed the 

following emission limits, except during periods of startup and shutdown 

. . . 

Using this specified sampling volume 

or test run duration . . . 

b. Filterable PM (or 

TSM).

9.8E–03 lb per MMBtu of heat input; 

or (8.3E–05 a lb per MMBtu of heat 

input).

Collect a minimum of 3 dscm per run. 

9. Suspension burners designed to 

burn biomass/bio-based solids.

a. CO (or CEMS) ....... 2,400 ppm by volume on a dry basis 

corrected to 3 percent oxygen, 3- 

run average; or (2,000 ppm by volume on a dry basis corrected to 3 

percent oxygen, 10-day rolling average).

1 hr minimum sampling time. 

b. Filterable PM (or 

TSM).

5.1E–02 lb per MMBtu of heat input; 

or (6.5E–03 lb per MMBtu of heat 

input).

Collect a minimum of 2 dscm per run. 

10. Dutch Ovens/Pile burners designed to burn biomass/bio-based 

solids.

a. CO (or CEMS) ....... 810 ppm by volume on a dry basis 

corrected to 3 percent oxygen, 3- 

run average; or (520 ppm by volume on a dry basis corrected to 3 

percent oxygen, 10-day rolling average).

1 hr minimum sampling time. 

b. Filterable PM (or 

TSM).

3.6E–02 lb per MMBtu of heat input; 

or (3.9E–05 lb per MMBtu of heat 

input).

Collect a minimum of 2 dscm per run. 

11. Fuel cell units designed to burn 

biomass/bio-based solids.

a. CO ......................... 910 ppm by volume on a dry basis 

corrected to 3 percent oxygen.

1 hr minimum sampling time. 

b. Filterable PM (or 

TSM).

2.0E–02 lb per MMBtu of heat input; 

or (2.9E–05 lb per MMBtu of heat 

input).

Collect a minimum of 2 dscm per run. 

12. Hybrid suspension grate boiler designed to burn biomass/bio-based 

solids.

a. CO (or CEMS) ....... 1,500 ppm by volume on a dry basis 

corrected to 3 percent oxygen, 3- 

run average; or (900 ppm by volume on a dry basis corrected to 3 

percent oxygen, 30-day rolling average).

1 hr minimum sampling time. 

b. Filterable PM (or 

TSM).

2.6E–02 lb per MMBtu of heat input; 

or (4.4E–04 lb per MMBtu of heat 

input).

Collect a minimum of 3 dscm per run. 

13. Units designed to burn liquid fuel .. a. HCl ........................ 1.2E–03 lb per MMBtu of heat input ... For M26A: Collect a minimum of 2 

dscm per run; for M26, collect a 

minimum of 240 liters per run. 

b. Mercury ................. 4.9E–07 a lb per MMBtu of heat input For M29, collect a minimum of 4 dscm 

per run; for M30A or M30B, collect 

a minimum sample as specified in 

the method; for ASTM D6784 b collect a minimum of 4 dscm. 

14. Units designed to burn heavy liquid fuel.a. CO (or CEMS) ....... 130 ppm by volume on a dry basis 

corrected to 3 percent oxygen, 3- 

run average; or (18 ppm by volume 

on a dry basis corrected to 3 percent oxygen, 10-day rolling average).

1 hr minimum sampling time. 

b. Filterable PM (or 

TSM).

1.3E–03 lb per MMBtu of heat input; 

or (7.5E–05 lb per MMBtu of heat 

input).

Collect a minimum of 3 dscm per run. 

15. Units designed to burn light liquid 

fuel.

a. CO (or CEMS) ....... 130 a ppm by volume on a dry basis 

corrected to 3 percent oxygen; or 

(60 ppm by volume on a dry basis 

corrected to 3 percent oxygen, 1- 

day block average)..

1 hr minimum sampling time. 

b. Filterable PM (or 

TSM).

1.1E–03 a lb per MMBtu of heat input; 

or (2.9E–05 lb per MMBtu of heat 

input).

Collect a minimum of 3 dscm per run. 

16. Units designed to burn liquid fuel 

that are non-continental units.

a. CO ......................... 130 ppm by volume on a dry basis 

corrected to 3 percent oxygen, 3- 

run average based on stack test; or 

(91 ppm by volume on a dry basis 

corrected to 3 percent oxygen, 3- 

hour rolling average).

1 hr minimum sampling time. 


tkelley on DSK3SPTVN1PROD with 
Federal Register / Vol. 78, No. 21 / Thursday, January 31, 2013 / Rules and Regulations 7213 

TABLE 13 TO SUBPART DDDDD OF PART 63—ALTERNATIVE EMISSION LIMITS FOR NEW OR RECONSTRUCTED BOILERS

AND PROCESS HEATERS THAT COMMENCED CONSTRUCTION OR RECONSTRUCTION AFTER DECEMBER 23, 2011, AND

BEFORE JANUARY 31, 2013—Continued 

If your boiler or process heater is in 

this subcategory . . . 

For the following pollutants . . . 

The emissions must not exceed the 

following emission limits, except during periods of startup and shutdown 

. . . 

Using this specified sampling volume 

or test run duration . . . 

b. Filterable PM (or 

TSM).

2.3E–02 lb per MMBtu of heat input; 

or (8.6E–04 lb per MMBtu of heat 

input).

Collect a minimum of 2 dscm per run. 

17. Units designed to burn gas 2 

(other) gases.

a. CO ......................... 130 ppm by volume on a dry basis 

corrected to 3 percent oxygen.

1 hr minimum sampling time. 

b. HCl ........................ 1.7E–03 lb per MMBtu of heat input ... For M26A, Collect a minimum of 2 

dscm per run; for M26, collect a 

minimum of 240 liters per run. 

c. Mercury .................. 7.9E–06 lb per MMBtu of heat input ... For M29, collect a minimum of 3 dscm 

per run; for M30A or M30B, collect 

a minimum sample as specified in 

the method; for ASTM D6784 b collect a minimum of 3 dscm. 

d. Filterable PM (or 

TSM).

6.7E–03 lb per MMBtu of heat input; 

or (2.1E–04 lb per MMBtu of heat 

input).

Collect a minimum of 3 dscm per run. 

a If you are conducting stack tests to demonstrate compliance and your performance tests for this pollutant for at least 2 consecutive years 

show that your emissions are at or below this limit and you are not required to conduct testing for CEMS or CPMS monitor certification, you can 

skip testing according to § 63.7515 if all of the other provision of § 63.7515 are met. For all other pollutants that do not contain a footnote ‘‘a’’, 

your performance tests for this pollutant for at least 2 consecutive years must show that your emissions are at or below 75 percent of this limit in 

order to qualify for skip testing. b Incorporated by reference, see § 63.14. 

[FR Doc. 2012–31646 Filed 1–30–13; 8:45 am] 

BILLING CODE 6560–50–P 


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