52738 Federal Register / Vol. 76, No. 163 / Tuesday, August 23, 2011 / Proposed Rules 

ENVIRONMENTAL PROTECTION 

AGENCY 

40 CFR Parts 60 and 63 

[EPA–HQ–OAR–2010–0505; FRL–9448–6] 

RIN 2060–AP76 

Oil and Natural Gas Sector: New 

Source Performance Standards and 

National Emission Standards for 

Hazardous Air Pollutants Reviews 

AGENCY: Environmental Protection 

Agency (EPA). 

ACTION: Proposed rule. 

SUMMARY: This action announces how 

the EPA proposes to address the reviews 

of the new source performance 

standards for volatile organic compound 

and sulfur dioxide emissions from 

natural gas processing plants. We are 

proposing to add to the source category 

list any oil and gas operation not 

covered by the current listing. This 

action also includes proposed 

amendments to the existing new source 

performance standards for volatile 

organic compounds from natural gas 

processing plants and proposed 

standards for operations that are not 

covered by the existing new source 

performance standards. In addition, this 

action proposes how the EPA will 

address the residual risk and technology 

review conducted for the oil and natural 

gas production and natural gas 

transmission and storage national 

emission standards for hazardous air 

pollutants. This action further proposes 

standards for emission sources within 

these two source categories that are not 

currently addressed, as well as 

amendments to improve aspects of these 

national emission standards for 

hazardous air pollutants related to 

applicability and implementation. 

Finally, this action addresses provisions 

in these new source performance 

standards and national emission 

standards for hazardous air pollutants 

related to emissions during periods of 

startup, shutdown and malfunction. 

DATES: Comments must be received on 

or before October 24, 2011. 

Public Hearing. Three public hearings 

will be held to provide the public an 

opportunity to provide comments on 

this proposed rulemaking. One will be 

held in the Dallas, Texas area, one in 

Pittsburgh, Pennsylvania, and one in 

Denver, Colorado, on dates to be 

announced in a separate document. 

Each hearing will convene at 10 a.m. 

local time. For additional information 

on the public hearings and requesting to 

speak, see the SUPPLEMENTARY

INFORMATION section of this preamble. 

ADDRESSES: Submit your comments, 

identified by Docket ID Number EPA– 

HQ–OAR–2010–0505, by one of the 

following methods: 

• Federal eRulemaking Portal: http:// 

www.regulations.gov: Follow the 

instructions for submitting comments. 

• Agency Web site: http:// 

www.epa.gov/oar/docket.html. Follow 

the instructions for submitting 

comments on the Air and Radiation 

Docket Web site. 

• E-mail: a-and-r-docket@epa.gov. 

Include Docket ID Number EPA–HQ– 

OAR–2010–0505 in the subject line of 

the message. 

• Facsimile: (202) 566–9744. 

• Mail: Attention Docket ID Number 

EPA–HQ–OAR–2010–0505, 1200 

Pennsylvania Ave., NW., Washington, 

DC 20460. Please include a total of two 

copies. In addition, please mail a copy 

of your comments on the information 

collection provisions to the Office of 

Information and Regulatory Affairs, 

Office of Management and Budget 

(OMB), Attn: Desk Officer for the EPA, 

725 17th Street, NW., Washington, DC 

20503. 

• Hand Delivery: United States 

Environmental Protection Agency, EPA 

West (Air Docket), Room 3334, 1301 

Constitution Ave., NW., Washington, 

DC 20004, Attention Docket ID Number 

EPA–HQ–OAR–2010–0505. Such 

deliveries are only accepted during the 

Docket’s normal hours of operation, and 

special arrangements should be made 

for deliveries of boxed information. 

Instructions: Direct your comments to 

Docket ID Number EPA–HQ–OAR– 

2010–0505. The EPA’s policy is that all 

comments received will be included in 

the public docket without change and 

may be made available online at http:// 

www.regulations.gov, including any 

personal information provided, unless 

the comment includes information 

claimed to be confidential business 

information (CBI) or other information 

whose disclosure is restricted by statute. 

Do not submit information that you 

consider to be CBI or otherwise 

protected through http:// 

www.regulations.gov or e-mail. The 

http://www.regulations.gov Web site is 

an ‘‘anonymous access’’ system, which 

means the EPA will not know your 

identity or contact information unless 

you provide it in the body of your 

comment. If you send an e-mail 

comment directly to the EPA without 

going through http:// 

www.regulations.gov, your e-mail 

address will be automatically captured 

and included as part of the comment 

that is placed in the public docket and 

made available on the Internet. If you 

submit an electronic comment, the EPA 

recommends that you include your 

name and other contact information in 

the body of your comment and with any 

disk or CD–ROM you submit. If the EPA 

cannot read your comment due to 

technical difficulties and cannot contact 

you for clarification, the EPA may not 

be able to consider your comment. 

Electronic files should avoid the use of 

special characters, any form of 

encryption, and be free of any defects or 

viruses. For additional information 

about the EPA’s public docket, visit the 

EPA Docket Center homepage at http:// 

www.epa.gov/epahome/dockets.htm. 

For additional instructions on 

submitting comments, go to section II.C 

of the SUPPLEMENTARY INFORMATION

section of this preamble. 

Docket: All documents in the docket 

are listed in the http:// 

www.regulations.gov index. Although 

listed in the index, some information is 

not publicly available, e.g., CBI or other 

information whose disclosure is 

restricted by statute. Certain other 

material, such as copyrighted material, 

is not placed on the Internet and will be 

publicly available only in hard copy. 

Publicly available docket materials are 

available either electronically through 

http://www.regulations.gov or in hard 

copy at the U.S. Environmental 

Protection Agency, EPA West (Air 

Docket), Room 3334, 1301 Constitution 

Ave., NW., Washington, DC 20004. The 

Public Reading Room is open from 

8:30 a.m. to 4:30 p.m., Monday through 

Friday, excluding legal holidays. The 

telephone number for the Public 

Reading Room is (202) 566–1744, and 

the telephone number for the Air Docket 

is (202) 566–1742. 

FOR FURTHER INFORMATION CONTACT: 

Bruce Moore, Sector Policies and 

Programs Division, Office of Air Quality 

Planning and Standards (E143–01), 

Environmental Protection Agency, 

Research Triangle Park, North Carolina 

27711, telephone number: (919) 541– 

5460; facsimile number: (919) 685–3200; 

e-mail address: moore.bruce@epa.gov. 

SUPPLEMENTARY INFORMATION: 

Organization of This Document. The 

following outline is provided to aid in 

locating information in this preamble. 

I. Preamble Acronyms and Abbreviations 

II. General Information 

A. Does this action apply to me? 

B. Where can I get a copy of this document 

and other related information? 

C. What should I consider as I prepare my 

comments for the EPA? 

D. When will a public hearing occur? 

III. Background Information 

A. What are standards of performance and 

NSPS? 

B. What are NESHAP? 


emcdonald on DSK2BSOYB1PROD with PROPOSALS2
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C. What litigation is related to this 

proposed action? 

D. What is a sector-based approach? 

IV. Oil and Natural Gas Sector 

V. Summary of Proposed Decisions and 

Actions 

A. What are the proposed revisions to the 

NSPS? 

B. What are the proposed decisions and 

actions related to the NESHAP? 

C. What are the proposed notification, 

recordkeeping and reporting 

requirements for this proposed action? 

D. What are the innovative compliance 

approaches being considered? 

E. How does the NSPS relate to permitting 

of sources? 

VI. Rationale for Proposed Action for NSPS 

A. What did we evaluate relative to NSPS? 

B. What are the results of our evaluations 

and proposed actions relative to NSPS? 

VII. Rationale for Proposed Action for 

NESHAP 

A. What data were used for the NESHAP 

analyses? 

B. What are the proposed decisions 

regarding certain unregulated emissions 

sources? 

C. How did we perform the risk assessment 

and what are the results and proposed 

decisions? 

D. How did we perform the technology 

review and what are the results and 

proposed decisions? 

E. What other actions are we proposing? 

VIII. What are the cost, environmental, 

energy and economic impacts of the 

proposed 40 CFR part 60, subpart OOOO 

and amendments to subparts HH and 

HHH of 40 CFR part 63? 

A. What are the affected sources? 

B. How are the impacts for this proposal 

evaluated? 

C. What are the air quality impacts? 

D. What are the water quality and solid 

waste impacts? 

E. What are the secondary impacts? 

F. What are the energy impacts? 

G. What are the cost impacts? 

H. What are the economic impacts? 

I. What are the benefits? 

IX. Request for Comments 

X. Submitting Data Corrections 

XI. 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 

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 

I. Preamble Acronyms and 

Abbreviations 

Several acronyms and terms used to 

describe industrial processes, data 

inventories and risk modeling are 

included in this preamble. While this 

may not be an exhaustive list, to ease 

the reading of this preamble and for 

reference purposes, the following terms 

and acronyms are defined here: 

ACGIH American Conference of 

Governmental Industrial Hygienists 

ADAF Age-Dependent Adjustment Factors 

AEGL Acute Exposure Guideline Levels 

AERMOD The air dispersion model used by 

the HEM–3 model 

API American Petroleum Institute 

BACT Best Available Control Technology 

BID Background Information Document 

BPD Barrels Per Day 

BSER Best System of Emission Reduction 

BTEX Benzene, Ethylbenzene, Toluene and 

Xylene 

CAA Clean Air Act 

CalEPA California Environmental 

Protection Agency 

CBI Confidential Business Information 

CEM Continuous Emissions Monitoring 

CEMS Continuous Emissions Monitoring 

System 

CFR Code of Federal Regulations 

CIIT Chemical Industry Institute of 

Toxicology 

CO Carbon Monoxide 

CO2 Carbon Dioxide 

CO2e Carbon Dioxide Equivalent 

DOE Department of Energy 

ECHO Enforcement and Compliance 

History Online 

e-GGRT Electronic Greenhouse Gas 

Reporting Tool 

EJ Environmental Justice 

EPA Environmental Protection Agency 

ERPG Emergency Response Planning 

Guidelines 

ERT Electronic Reporting Tool 

GCG Gas Condensate Glycol 

GHG Greenhouse Gas 

GOR Gas to Oil Ratio 

GWP Global Warming Potential 

HAP Hazardous Air Pollutants 

HEM–3 Human Exposure Model, version 3 

HI Hazard Index 

HP Horsepower 

HQ Hazard Quotient 

H2S Hydrogen Sulfide 

ICR Information Collection Request 

IPCC Intergovernmental Panel on Climate 

Change 

IRIS Integrated Risk Information System 

km Kilometer 

kW Kilowatts 

LAER Lowest Achievable Emission Rate 

lb Pounds 

LDAR Leak Detection and Repair 

MACT Maximum Achievable Control 

Technology 

MACT Code Code within the NEI used to 

identify processes included in a source 

category 

Mcf Thousand Cubic Feet 

Mg/yr Megagrams per year 

MIR Maximum Individual Risk 

MIRR Monitoring, Inspection, 

Recordkeeping and Reporting 

MMtCO2e Million Metric Tons of Carbon 

Dioxide Equivalents 

NAAQS National Ambient Air Quality 

Standards 

NAC/AEGL National Advisory Committee 

for Acute Exposure Guideline Levels for 

Hazardous Substances 

NAICS North American Industry 

Classification System 

NAS National Academy of Sciences 

NATA National Air Toxics Assessment 

NEI National Emissions Inventory 

NEMS National Energy Modeling System 

NESHAP National Emissions Standards for 

Hazardous Air Pollutants 

NGL Natural Gas Liquids 

NIOSH National Institutes for Occupational 

Safety and Health 

NOX Oxides of Nitrogen 

NRC National Research Council 

NSPS New Source Performance Standards 

NSR New Source Review 

NTTAA National Technology Transfer and 

Advancement Act 

OAQPS Office of Air Quality Planning and 

Standards 

OMB Office of Management and Budget 

PB–HAP Hazardous air pollutants known to 

be persistent and bio-accumulative in the 

environment 

PFE Potential for Flash Emissions 

PM Particulate Matter 

PM2.5 Particulate Matter (2.5 microns and 

less) 

POM Polycyclic Organic Matter 

PPM Parts Per Million 

PPMV Parts Per Million by Volume 

PSIG Pounds per square inch gauge 

PTE Potential to Emit 

QA Quality Assurance 

RACT Reasonably Available Control 

Technology 

RBLC RACT/BACT/LAER Clearinghouse 

REC Reduced Emissions Completions 

REL CalEPA Reference Exposure Level 

RFA Regulatory Flexibility Act 

RfC Reference Concentration 

RfD Reference Dose 

RIA Regulatory Impact Analysis 

RICE Reciprocating Internal Combustion 

Engines 

RTR Residual Risk and Technology Review 

SAB Science Advisory Board 

SBREFA Small Business Regulatory 

Enforcement Fairness Act 

SCC Source Classification Codes 

SCFH Standard Cubic Feet Per Hour 

SCFM Standard Cubic Feet Per Minute 

SCM Standard Cubic Meters 

SCMD Standard Cubic Meters Per Day 

SCOT Shell Claus Offgas Treatment 

SIP State Implementation Plan 

SISNOSE Significant Economic Impact on a 

Substantial Number of Small Entities 

S/L/T State and Local and Tribal Agencies 

SO2 Sulfur Dioxide 

SSM Startup, Shutdown and Malfunction 

STEL Short-term Exposure Limit 

TLV Threshold Limit Value 

TOSHI Target Organ-Specific Hazard Index 

TPY Tons per Year 

TRIM Total Risk Integrated Modeling System 

TRIM.FaTE A spatially explicit, 

compartmental mass balance model that 


emcdonald on DSK2BSOYB1PROD with PROPOSALS2
52740 Federal Register / Vol. 76, No. 163 / Tuesday, August 23, 2011 / Proposed Rules 

describes the movement and 

transformation of pollutants over time, 

through a user-defined, bounded system 

that includes both biotic and abiotic 

compartments 

TSD Technical Support Document 

UF Uncertainty Factor 

UMRA Unfunded Mandates Reform Act 

URE Unit Risk Estimate 

VCS Voluntary Consensus Standards 

VOC Volatile Organic Compounds 

VRU Vapor Recovery Unit 

II. General Information 

A. Does this action apply to me? 

The regulated industrial source 

categories that are the subject of this 

proposal are listed in Table 1 of this 

preamble. These standards and any 

changes considered in this rulemaking 

would be directly applicable to sources 

as a Federal program. Thus, Federal, 

state, local and tribal government 

entities are not affected by this proposed 

action. 

TABLE 1—INDUSTRIAL SOURCE CATEGORIES AFFECTED BY THIS PROPOSED ACTION

Category NAICS 

code 1 Examples of regulated entities 

Industry ..................................................................... 211111 Crude Petroleum and Natural Gas Extraction.

211112 Natural Gas Liquid Extraction. 

221210 Natural Gas Distribution. 

486110 Pipeline Distribution of Crude Oil. 

486210 Pipeline Transportation of Natural Gas. 

Federal government ................................................. .................... Not affected. 

State/local/tribal government .................................... .................... Not affected. 

1 North American Industry Classification System. 

This table is not intended to be 

exhaustive, but rather provides a guide 

for readers regarding entities likely to be 

affected by this action. To determine 

whether your facility would be 

regulated by this action, you should 

examine the applicability criteria in the 

regulations. If you have any questions 

regarding the applicability of this action 

to a particular entity, contact the person 

listed in the preceding FOR FURTHER

INFORMATION CONTACT section. 

B. Where can I get a copy of this 

document and other related 

information? 

In addition to being available in the 

docket, an electronic copy of this 

proposal will also be available on the 

EPA’s Web site. Following signature by 

the EPA Administrator, a copy of this 

proposed action will be posted on the 

EPA’s Web site at the following address: 

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

oilandgas. 

Additional information is available on 

the EPA’s Residual Risk and Technology 

Review (RTR) Web site at http:// 

www.epa.gov/ttn/atw/rrisk/oarpg.html. 

This information includes the most 

recent version of the rule, source 

category descriptions, detailed 

emissions and other data that were used 

as inputs to the risk assessments. 

C. What should I consider as I prepare 

my comments for the EPA? 

Submitting CBI. Do not submit 

information containing CBI to the EPA 

through http://www.regulations.gov or 

e-mail. Clearly mark the part or all of 

the information that you claim to be 

CBI. For CBI information on a disk or 

CD ROM that you mail to the EPA, mark 

the outside of the disk or CD ROM as 

CBI and then identify electronically 

within the disk or CD ROM the specific 

information that is claimed as CBI. In 

addition to one complete version of the 

comment that includes information 

claimed as CBI, a copy of the comment 

that does not contain the information 

claimed as CBI must be submitted for 

inclusion in the public docket. If you 

submit a CD ROM or disk that does not 

contain CBI, mark the outside of the 

disk or CD ROM clearly that it does not 

contain CBI. Information not marked as 

CBI will be included in the public 

docket and the EPA’s electronic public 

docket without prior notice. Information 

marked as CBI will not be disclosed 

except in accordance with procedures 

set forth in 40 CFR part 2. Send or 

deliver information identified as CBI 

only to the following address: Roberto 

Morales, OAQPS Document Control 

Officer (C404–02), Environmental 

Protection Agency, Office of Air Quality 

Planning and Standards, Research 

Triangle Park, North Carolina 27711, 

Attention Docket ID Number EPA–HQ– 

OAR–2010–0505. 

D. When will a public hearing occur? 

We will hold three public hearings, 

one in the Dallas, Texas area, one in 

Pittsburgh, Pennsylvania, and one in 

Denver, Colorado. If you are interested 

in attending or speaking at one of the 

public hearings, contact Ms. Joan Rogers 

at (919) 541–4487 by September 6, 2011. 

Details on the public hearings will be 

provided in a separate notice and we 

will specify the time and date of the 

public hearings on http://www.epa.gov/ 

airquality/oilandgas. If no one requests 

to speak at one of the public hearings by 

September 6, 2011, then that public 

hearing will be cancelled without 

further notice. 

III. Background Information 

A. What are standards of performance 

and NSPS? 

1. What is the statutory authority for 

standards of performance and NSPS? 

Section 111 of the Clean Air Act 

(CAA) requires the EPA Administrator 

to list categories of stationary sources, if 

such sources cause or contribute 

significantly to air pollution, which may 

reasonably be anticipated to endanger 

public health or welfare. The EPA must 

then issue performance standards for 

such source categories. A performance 

standard reflects the degree of emission 

limitation achievable through the 

application of the ‘‘best system of 

emission reduction’’ (BSER) which the 

EPA determines has been adequately 

demonstrated. The EPA may consider 

certain costs and nonair quality health 

and environmental impact and energy 

requirements when establishing 

performance standards. Whereas CAA 

section 112 standards are issued for 

existing and new stationary sources, 

standards of performance are issued for 

new and modified stationary sources. 

These standards are referred to as new 

source performance standards (NSPS). 

The EPA has the authority to define the 

source categories, determine the 

pollutants for which standards should 

be developed, identify the facilities 

within each source category to be 

covered and set the emission level of the 

standards. 

CAA section 111(b)(1)(B) requires the 

EPA to ‘‘at least every 8 years review 

and, if appropriate, revise’’ performance 

standards unless the ‘‘Administrator 

determines that such review is not 

appropriate in light of readily available 

information on the efficacy’’ of the 


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Federal Register / Vol. 76, No. 163 / Tuesday, August 23, 2011 / Proposed Rules 52741 

standard. When conducting a review of 

an existing performance standard, the 

EPA has discretion to revise that 

standard to add emission limits for 

pollutants or emission sources not 

currently regulated for that source 

category. 

In setting or revising a performance 

standard, CAA section 111(a)(1) 

provides that performance standards are 

to ‘‘reflect the degree of emission 

limitation achievable through the 

application of the best system of 

emission reduction which (taking into 

account the cost of achieving such 

reduction and any nonair quality health 

and environmental impact and energy 

requirements) the Administrator 

determines has been adequately 

demonstrated.’’ In this notice, we refer 

to this level of control as the BSER. In 

determining BSER, we typically conduct 

a technology review that identifies what 

emission reduction systems exist and 

how much they reduce air pollution in 

practice. Next, for each control system 

identified, we evaluate its costs, 

secondary air benefits (or disbenefits) 

resulting from energy requirements and 

nonair quality impacts such as solid 

waste generation. Based on our 

evaluation, we would determine BSER. 

The resultant standard is usually a 

numerical emissions limit, expressed as 

a performance level (i.e., a rate-based 

standard or percent control), that 

reflects the BSER. Although such 

standards are based on the BSER, the 

EPA may not prescribe a particular 

technology that must be used to comply 

with a performance standard, except in 

instances where the Administrator 

determines it is not feasible to prescribe 

or enforce a standard of performance. 

Typically, sources remain free to elect 

whatever control measures that they 

choose to meet the emission limits. 

Upon promulgation, an NSPS becomes 

a national standard to which all new, 

modified or reconstructed sources must 

comply. 

2. What is the regulatory history 

regarding performance standards for the 

oil and natural gas sector? 

In 1979, the EPA listed crude oil and 

natural gas production on its priority 

list of source categories for 

promulgation of NSPS (44 FR 49222, 

August 21, 1979). On June 24, 1985 (50 

FR 26122), the EPA promulgated an 

NSPS for the source category that 

addressed volatile organic compound 

(VOC) emissions from leaking 

components at onshore natural gas 

processing plants (40 CFR part 60, 

subpart KKK). On October 1, 1985 (50 

FR 40158), a second NSPS was 

promulgated for the source category that 

regulates sulfur dioxide (SO2) emissions 

from natural gas processing plants (40 

CFR part 60, subpart LLL). Other than 

natural gas processing plants, EPA has 

not previously set NSPS for a variety of 

oil and natural gas operations. 

B. What are NESHAP? 

1. What is the statutory authority for 

NESHAP? 

Section 112 of the CAA establishes a 

two-stage regulatory process to address 

emissions of hazardous air pollutants 

(HAP) from stationary sources. In the 

first stage, after the EPA has identified 

categories of sources emitting one or 

more of the HAP listed in section 112(b) 

of the CAA, section 112(d) of the CAA 

calls for us to promulgate national 

emission standards for hazardous air 

pollutants (NESHAP) for those sources. 

‘‘Major sources’’ are those that emit or 

have the potential to emit (PTE) 10 tons 

per year (tpy) or more of a single HAP 

or 25 tpy or more of any combination of 

HAP. For major sources, these 

technology-based standards must reflect 

the maximum degree of emission 

reductions of HAP achievable (after 

considering cost, energy requirements 

and nonair quality health and 

environmental impacts) and are 

commonly referred to as maximum 

achievable control technology (MACT) 

standards. 

MACT standards are to reflect 

application of measures, processes, 

methods, systems or techniques, 

including, but not limited to, measures 

which, (1) reduce the volume of or 

eliminate pollutants through process 

changes, substitution of materials or 

other modifications, (2) enclose systems 

or processes to eliminate emissions, (3) 

capture or treat pollutants when 

released from a process, stack, storage or 

fugitive emissions point, (4) are design, 

equipment, work practice or operational 

standards (including requirements for 

operator training or certification) or (5) 

are a combination of the above. CAA 

section 112(d)(2)(A)–(E). The MACT 

standard may take the form of a design, 

equipment, work practice or operational 

standard where the EPA first determines 

either that, (1) a pollutant cannot be 

emitted through a conveyance designed 

and constructed to emit or capture the 

pollutant or that any requirement for or 

use of such a conveyance would be 

inconsistent with law or (2) the 

application of measurement 

methodology to a particular class of 

sources is not practicable due to 

technological and economic limitations. 

CAA sections 112(h)(1)–(2). 

The MACT ‘‘floor’’ is the minimum 

control level allowed for MACT 

standards promulgated under CAA 

section 112(d)(3), and may not be based 

on cost considerations. For new sources, 

the MACT floor cannot be less stringent 

than the emission control that is 

achieved in practice by the bestcontrolled similar source. The MACT 

floors for existing sources can be less 

stringent than floors for new sources, 

but they cannot be less stringent than 

the average emission limitation 

achieved by the best-performing 12 

percent of existing sources in the 

category or subcategory (or the bestperforming five sources for categories or 

subcategories with fewer than 30 

sources). In developing MACT 

standards, we must also consider 

control options that are more stringent 

than the floor. We may establish 

standards more stringent than the floor 

based on the consideration of the cost of 

achieving the emissions reductions, any 

nonair quality health and environmental 

impacts and energy requirements. 

The EPA is then required to review 

these technology-based standards and to 

revise them ‘‘as necessary (taking into 

account developments in practices, 

processes, and control technologies)’’ no 

less frequently than every 8 years, under 

CAA section 112(d)(6). In conducting 

this review, the EPA is not obliged to 

completely recalculate the prior MACT 

determination. NRDC v. EPA, 529 F.3d 

1077, 1084 (D.C. Cir. 2008). 

The second stage in standard-setting 

focuses on reducing any remaining 

‘‘residual’’ risk according to CAA 

section 112(f). This provision requires, 

first, that the EPA prepare a Report to 

Congress discussing (among other 

things) methods of calculating risk 

posed (or potentially posed) by sources 

after implementation of the MACT 

standards, the public health significance 

of those risks, and the EPA’s 

recommendations as to legislation 

regarding such remaining risk. The EPA 

prepared and submitted this report 

(Residual Risk Report to Congress, EPA– 

453/R–99–001) in March 1999. Congress 

did not act in response to the report, 

thereby triggering the EPA’s obligation 

under CAA section 112(f)(2) to analyze 

and address residual risk. 

CAA section 112(f)(2) requires us to 

determine for source categories subject 

to MACT standards, whether the 

emissions standards provide an ample 

margin of safety to protect public health. 

If the MACT standards for HAP 

‘‘classified as a known, probable, or 

possible human carcinogen do not 

reduce lifetime excess cancer risks to 

the individual most exposed to 

emissions from a source in the category 

or subcategory to less than 1-in-1 

million,’’ the EPA must promulgate 


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52742 Federal Register / Vol. 76, No. 163 / Tuesday, August 23, 2011 / Proposed Rules 

1 ‘‘Adverse environmental effect’’ is defined in 

CAA section 112(a)(7) as any significant and 

widespread adverse effect, which may be 

reasonably anticipated to wildlife, aquatic life or 

natural resources, including adverse impacts on 

populations of endangered or threatened species or 

significant degradation of environmental qualities 

over broad areas. 

residual risk standards for the source 

category (or subcategory), as necessary, 

to provide an ample margin of safety to 

protect public health. In doing so, the 

EPA may adopt standards equal to 

existing MACT standards if the EPA 

determines that the existing standards 

are sufficiently protective. NRDC v. 

EPA, 529 F.3d 1077, 1083 (D.C. Cir. 

2008). (‘‘If EPA determines that the 

existing technology-based standards 

provide an ‘‘ample margin of safety,’’ 

then the Agency is free to readopt those 

standards during the residual risk 

rulemaking.’’) The EPA must also adopt 

more stringent standards, if necessary, 

to prevent an adverse environmental 

effect,1 but must consider cost, energy, 

safety and other relevant factors in 

doing so. 

Section 112(f)(2) of the CAA expressly 

preserves our use of a two-step process 

for developing standards to address any 

residual risk and our interpretation of 

‘‘ample margin of safety’’ developed in 

the National Emission Standards for 

Hazardous Air Pollutants: Benzene 

Emissions from Maleic Anhydride 

Plants, Ethylbenzene/Styrene Plants, 

Benzene Storage Vessels, Benzene 

Equipment Leaks, and Coke By-Product 

Recovery Plants (Benzene NESHAP) (54 

FR 38044, September 14, 1989). The 

first step in this process is the 

determination of acceptable risk. The 

second step provides for an ample 

margin of safety to protect public health, 

which is the level at which the 

standards are set (unless a more 

stringent standard is required to 

prevent, taking into consideration costs, 

energy, safety, and other relevant 

factors, an adverse environmental 

effect). 

The terms ‘‘individual most exposed,’’ 

‘‘acceptable level,’’ and ‘‘ample margin 

of safety’’ are not specifically defined in 

the CAA. However, CAA section 

112(f)(2)(B) preserves the interpretation 

set out in the Benzene NESHAP, and the 

United States Court of Appeals for the 

District of Columbia Circuit in NRDC v. 

EPA, 529 F.3d 1077, concluded that the 

EPA’s interpretation of subsection 

112(f)(2) is a reasonable one. See NRDC 

v. EPA, 529 F.3d at 1083 (D.C. Cir., 

‘‘[S]ubsection 112(f)(2)(B) expressly 

incorporates EPA’s interpretation of the 

Clean Air Act from the Benzene 

standard, complete with a citation to the 

Federal Register’’). (D.C. Cir. 2008). See 

also, A Legislative History of the Clean 

Air Act Amendments of 1990, volume 1, 

p. 877 (Senate debate on Conference 

Report). We notified Congress in the 

Residual Risk Report to Congress that 

we intended to use the Benzene 

NESHAP approach in making CAA 

section 112(f) residual risk 

determinations (EPA–453/R–99–001, p. 

ES–11). 

In the Benzene NESHAP, we stated as 

an overall objective: 

* * * in protecting public health with an 

ample margin of safety, we strive to provide 

maximum feasible protection against risks to 

health from hazardous air pollutants by, (1) 

protecting the greatest number of persons 

possible to an individual lifetime risk level 

no higher than approximately 1-in-1 million; 

and (2) limiting to no higher than 

approximately 1-in-10 thousand [i.e., 100-in1 million] the estimated risk that a person 

living near a facility would have if he or she 

were exposed to the maximum pollutant 

concentrations for 70 years. 

The Agency also stated that, ‘‘The 

EPA also considers incidence (the 

number of persons estimated to suffer 

cancer or other serious health effects as 

a result of exposure to a pollutant) to be 

an important measure of the health risk 

to the exposed population. Incidence 

measures the extent of health risk to the 

exposed population as a whole, by 

providing an estimate of the occurrence 

of cancer or other serious health effects 

in the exposed population.’’ The Agency 

went on to conclude that ‘‘estimated 

incidence would be weighed along with 

other health risk information in judging 

acceptability.’’ As explained more fully 

in our Residual Risk Report to Congress, 

the EPA does not define ‘‘rigid line[s] of 

acceptability,’’ but considers rather 

broad objectives to be weighed with a 

series of other health measures and 

factors (EPA–453/R–99–001, p. ES–11). 

The determination of what represents an 

‘‘acceptable’’ risk is based on a 

judgment of ‘‘what risks are acceptable 

in the world in which we live’’ 

(Residual Risk Report to Congress, p. 

178, quoting the Vinyl Chloride 

decision at 824 F.2d 1165) recognizing 

that our world is not risk-free. 

In the Benzene NESHAP, we stated 

that ‘‘EPA will generally presume that if 

the risk to [the maximum exposed] 

individual is no higher than 

approximately 1-in-10 thousand, that 

risk level is considered acceptable.’’ 54 

FR 38045. We discussed the maximum 

individual lifetime cancer risk (or 

maximum individual risk (MIR)) as 

being ‘‘the estimated risk that a person 

living near a plant would have if he or 

she were exposed to the maximum 

pollutant concentrations for 70 years.’’ 

Id. We explained that this measure of 

risk ‘‘is an estimate of the upper bound 

of risk based on conservative 

assumptions, such as continuous 

exposure for 24 hours per day for 70 

years.’’ Id. We acknowledge that 

maximum individual lifetime cancer 

risk ‘‘does not necessarily reflect the 

true risk, but displays a conservative 

risk level which is an upper-bound that 

is unlikely to be exceeded.’’ Id. 

Understanding that there are both 

benefits and limitations to using 

maximum individual lifetime cancer 

risk as a metric for determining 

acceptability, we acknowledged in the 

1989 Benzene NESHAP that 

‘‘consideration of maximum individual 

risk * * * must take into account the 

strengths and weaknesses of this 

measure of risk.’’ Id. Consequently, the 

presumptive risk level of 100-in-1 

million (1-in-10 thousand) provides a 

benchmark for judging the acceptability 

of maximum individual lifetime cancer 

risk, but does not constitute a rigid line 

for making that determination. 

The Agency also explained in the 

1989 Benzene NESHAP the following: 

‘‘In establishing a presumption for MIR, 

rather than a rigid line for acceptability, 

the Agency intends to weigh it with a 

series of other health measures and 

factors. These include the overall 

incidence of cancer or other serious 

health effects within the exposed 

population, the numbers of persons 

exposed within each individual lifetime 

risk range and associated incidence 

within, typically, a 50-kilometer (km) 

exposure radius around facilities, the 

science policy assumptions and 

estimation uncertainties associated with 

the risk measures, weight of the 

scientific evidence for human health 

effects, other quantified or unquantified 

health effects, effects due to co-location 

of facilities and co-emission of 

pollutants.’’ Id. 

In some cases, these health measures 

and factors taken together may provide 

a more realistic description of the 

magnitude of risk in the exposed 

population than that provided by 

maximum individual lifetime cancer 

risk alone. As explained in the Benzene 

NESHAP, ‘‘[e]ven though the risks 

judged ‘‘acceptable’’ by the EPA in the 

first step of the Vinyl Chloride inquiry 

are already low, the second step of the 

inquiry, determining an ‘‘ample margin 

of safety,’’ again includes consideration 

of all of the health factors, and whether 

to reduce the risks even further.’’ In the 

ample margin of safety decision process, 

the Agency again considers all of the 

health risks and other health 

information considered in the first step. 

Beyond that information, additional 

factors relating to the appropriate level 


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2Although defined as ‘‘maximum individual 

risk,’’ MIR refers only to cancer risk. MIR, one 

metric for assessing cancer risk, is the estimated 

risk were an individual exposed to the maximum 

level of a pollutant for a lifetime. 

3On April 27, 2011, pursuant to paragraph 10(a) 

of the Consent Decree, the parties filed with the 

Court a written stipulation that changes the 

proposal date from January 31, 2011, to July 28, 

2011, and the final action date from November 30, 

2011, to February 28, 2012. 

of control will also be considered, 

including costs and economic impacts 

of controls, technological feasibility, 

uncertainties and any other relevant 

factors. Considering all of these factors, 

the Agency will establish the standard 

at a level that provides an ample margin 

of safety to protect the public health, as 

required by CAA section 112(f). 54 FR 

38046. 

2. How do we consider the risk results 

in making decisions? 

As discussed in the previous section 

of this preamble, we apply a two-step 

process for developing standards to 

address residual risk. In the first step, 

the EPA determines if risks are 

acceptable. This determination 

‘‘considers all health information, 

including risk estimation uncertainty, 

and includes a presumptive limit on 

maximum individual lifetime [cancer] 

risk (MIR) 2 of approximately 1-in-10 

thousand [i.e., 100-in-1 million].’’ 54 FR 

38045. In the second step of the process, 

the EPA sets the standard at a level that 

provides an ample margin of safety ‘‘in 

consideration of all health information, 

including the number of persons at risk 

levels higher than approximately 1-in-1 

million, as well as other relevant factors, 

including costs and economic impacts, 

technological feasibility, and other 

factors relevant to each particular 

decision.’’ Id. 

In past residual risk determinations, 

the EPA presented a number of human 

health risk metrics associated with 

emissions from the category under 

review, including: The MIR; the 

numbers of persons in various risk 

ranges; cancer incidence; the maximum 

noncancer hazard index (HI); and the 

maximum acute noncancer hazard. In 

estimating risks, the EPA considered 

source categories under review that are 

located near each other and that affect 

the same population. The EPA provided 

estimates of the expected difference in 

actual emissions from the source 

category under review and emissions 

allowed pursuant to the source category 

MACT standard. The EPA also 

discussed and considered risk 

estimation uncertainties. The EPA is 

providing this same type of information 

in support of these actions. 

The Agency acknowledges that the 

Benzene NESHAP provides flexibility 

regarding what factors the EPA might 

consider in making our determinations 

and how they might be weighed for each 

source category. In responding to 

comment on our policy under the 

Benzene NESHAP, the EPA explained 

that: ‘‘The policy chosen by the 

Administrator permits consideration of 

multiple measures of health risk. Not 

only can the MIR figure be considered, 

but also incidence, the presence of 

noncancer health effects, and the 

uncertainties of the risk estimates. In 

this way, the effect on the most exposed 

individuals can be reviewed as well as 

the impact on the general public. These 

factors can then be weighed in each 

individual case. This approach complies 

with the Vinyl Chloride mandate that 

the Administrator ascertain an 

acceptable level of risk to the public by 

employing [her] expertise to assess 

available data. It also complies with the 

Congressional intent behind the CAA, 

which did not exclude the use of any 

particular measure of public health risk 

from the EPA’s consideration with 

respect to CAA section 112 regulations, 

and, thereby, implicitly permits 

consideration of any and all measures of 

health risk which the Administrator, in 

[her] judgment, believes are appropriate 

to determining what will ‘protect the 

public health.’ ’’ 

For example, the level of the MIR is 

only one factor to be weighed in 

determining acceptability of risks. The 

Benzene NESHAP explains ‘‘an MIR of 

approximately 1-in-10 thousand should 

ordinarily be the upper end of the range 

of acceptability. As risks increase above 

this benchmark, they become 

presumptively less acceptable under 

CAA section 112, and would be 

weighed with the other health risk 

measures and information in making an 

overall judgment on acceptability. Or, 

the Agency may find, in a particular 

case, that a risk that includes MIR less 

than the presumptively acceptable level 

is unacceptable in the light of other 

health risk factors.’’ Similarly, with 

regard to the ample margin of safety 

analysis, the Benzene NESHAP states 

that: ‘‘EPA believes the relative weight 

of the many factors that can be 

considered in selecting an ample margin 

of safety can only be determined for 

each specific source category. This 

occurs mainly because technological 

and economic factors (along with the 

health-related factors) vary from source 

category to source category.’’ 

3. What is the regulatory history 

regarding NESHAP for the oil and 

natural gas sector? 

On July 16, 1992 (57 FR 31576), the 

EPA published a list of major and area 

sources for which NESHAP are to be 

published (i.e., the source category list). 

Oil and natural gas production facilities 

were listed as a category of major 

sources. On February 12, 1998 (63 FR 

7155), the EPA amended the source 

category list to add Natural Gas 

Transmission and Storage as a major 

source category. 

On June 17, 1999 (64 FR 32610), the 

EPA promulgated MACT standards for 

the Oil and Natural Gas Production and 

Natural Gas Transmission and Storage 

major source categories. The Oil and 

Natural Gas Production NESHAP (40 

CFR part 63, subpart HH) contains 

standards for HAP emissions from 

glycol dehydration process vents, 

storage vessels and natural gas 

processing plant equipment leaks. The 

Natural Gas Transmission and Storage 

NESHAP (40 CFR part 63, subpart HHH) 

contains standards for glycol 

dehydration process vents. 

In addition to these NESHAP for 

major sources, the EPA also 

promulgated NESHAP for the Oil and 

Natural Gas Production area source 

category on January 3, 2007 (72 FR 26). 

These area source standards, which are 

based on generally available control 

technology, are also contained in 40 

CFR part 63, subpart HH. This proposed 

action does not impact these area source 

standards. 

C. What litigation is related to this 

proposed action? 

On January 14, 2009, pursuant to 

section 304(a)(2) of the CAA, WildEarth 

Guardians and the San Juan Citizens 

Alliance filed a Complaint alleging that 

the EPA failed to meet its obligations 

under CAA sections 111(b)(1)(B), 

112(d)(6) and 112(f)(2) to take actions 

relative to the review/revision of the 

NSPS and the NESHAP with respect to 

the Oil and Natural Gas Production 

source category. On February 4, 2010, 

the Court entered a consent decree 

requiring the EPA to sign by July 28, 

2011,3 proposed standards and/or 

determinations not to issue standards 

pursuant to CAA sections 111(b)(1)(B), 

112(d)(6) and 112(f)(2) and to take final 

action by February 28, 2012. 

D. What is a sector-based approach? 

Sector-based approaches are based on 

integrated assessments that consider 

multiple pollutants in a comprehensive 

and coordinated manner to manage 

emissions and CAA requirements. One 

of the many ways we can address sectorbased approaches is by reviewing 

multiple regulatory programs together 

whenever possible, consistent with all 


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applicable legal requirements. This 

approach essentially expands the 

technical analyses on costs and benefits 

of particular technologies, to consider 

the interactions of rules that regulate 

sources. The benefit of multi-pollutant 

and sector-based analyses and 

approaches includes the ability to 

identify optimum strategies, considering 

feasibility, cost impacts and benefits 

across the different pollutant types 

while streamlining administrative and 

compliance complexities and reducing 

conflicting and redundant requirements, 

resulting in added certainty and easier 

implementation of control strategies for 

the sector under consideration. In order 

to benefit from a sector-based approach 

for the oil and gas industry, the EPA 

analyzed how the NSPS and NESHAP 

under consideration relate to each other 

and other regulatory requirements 

currently under review for oil and gas 

facilities. In this analysis, we looked at 

how the different control requirements 

that result from these requirements 

interact, including the different 

regulatory deadlines and control 

equipment requirements that result, the 

different reporting and recordkeeping 

requirements and opportunities for 

states to account for reductions resulting 

from this rulemaking in their State 

Implementation Plans (SIP). The 

requirements analyzed affect criteria 

pollutant, HAP and methane emissions 

from oil and natural gas processes and 

cover the NSPS and NESHAP reviews. 

As a result of the sector-based approach, 

this rulemaking will reduce conflicting 

and redundant requirements. Also, the 

sector-based approach facilitated the 

streamlining of monitoring, 

recordkeeping and reporting 

requirements, thus, reducing 

administrative and compliance 

complexities associated with complying 

with multiple regulations. In addition, 

the sector-based approach promotes a 

comprehensive control strategy that 

maximizes the co-control of multiple 

regulated pollutants while obtaining 

emission reductions as co-benefits. 

IV. Oil and Natural Gas Sector 

The oil and natural gas sector 

includes operations involved in the 

extraction and production of oil and 

natural gas, as well as the processing, 

transmission and distribution of natural 

gas. Specifically for oil, the sector 

includes all operations from the well to 

the point of custody transfer at a 

petroleum refinery. For natural gas, the 

sector includes all operations from the 

well to the customer. The oil and 

natural gas operations can generally be 

separated into four segments: (1) Oil and 

natural gas production, (2) natural gas 

processing, (3) natural gas transmission 

and (4) natural gas distribution. Each of 

these segments is briefly discussed 

below. 

Oil and natural gas production 

includes both onshore and offshore 

operations. Production operations 

include the wells and all related 

processes used in the extraction, 

production, recovery, lifting, 

stabilization, separation or treating of oil 

and/or natural gas (including 

condensate). Production components 

may include, but are not limited to, 

wells and related casing head, tubing 

head and ‘‘Christmas tree’’ piping, as 

well as pumps, compressors, heater 

treaters, separators, storage vessels, 

pneumatic devices and dehydrators. 

Production operations also include the 

well drilling, completion and workover 

processes and includes all the portable 

non-self-propelled apparatus associated 

with those operations. Production sites 

include not only the ‘‘pads’’ where the 

wells are located, but also include 

stand-alone sites where oil, condensate, 

produced water and gas from several 

wells may be separated, stored and 

treated. The production sector also 

includes the low pressure, small 

diameter, gathering pipelines and 

related components that collect and 

transport the oil, gas and other materials 

and wastes from the wells to the 

refineries or natural gas processing 

plants. None of the operations upstream 

of the natural gas processing plant are 

covered by the existing NSPS. Offshore 

oil and natural gas production occurs on 

platform structures that house 

equipment to extract oil and gas from 

the ocean or lake floor and that process 

and/or transfer the oil and gas to 

storage, transport vessels or onshore. 

Offshore production can also include 

secondary platform structures 

connected to the platform structure, 

storage tanks associated with the 

platform structure and floating 

production and offloading equipment. 

There are three basic types of wells: 

Oil wells, gas wells and associated gas 

wells. Oil wells can have ‘‘associated’’ 

natural gas that is separated and 

processed or the crude oil can be the 

only product processed. Once the crude 

oil is separated from the water and other 

impurities, it is essentially ready to be 

transported to the refinery via truck, 

railcar or pipeline. We consider the oil 

refinery sector separately from the oil 

and natural gas sector. Therefore, at the 

point of custody transfer at the refinery, 

the oil leaves the oil and natural gas 

sector and enters the petroleum refining 

sector. 

Natural gas is primarily made up of 

methane. However, whether natural gas 

is associated gas from oil wells or nonassociated gas from gas or condensate 

wells, it commonly exists in mixtures 

with other hydrocarbons. These 

hydrocarbons are often referred to as 

natural gas liquids (NGL). They are sold 

separately and have a variety of 

different uses. The raw natural gas often 

contains water vapor, hydrogen sulfide 

(H2S), carbon dioxide (CO2), helium, 

nitrogen and other compounds. Natural 

gas processing consists of separating 

certain hydrocarbons and fluids from 

the natural gas to produced ‘‘pipeline 

quality’’ dry natural gas. While some of 

the processing can be accomplished in 

the production segment, the complete 

processing of natural gas takes place in 

the natural gas processing segment. 

Natural gas processing operations 

separate and recover NGL or other nonmethane gases and liquids from a stream 

of produced natural gas through 

components performing one or more of 

the following processes: Oil and 

condensate separation, water removal, 

separation of NGL, sulfur and CO2

removal, fractionation of natural gas 

liquid and other processes, such as the 

capture of CO2 separated from natural 

gas streams for delivery outside the 

facility. Natural gas processing plants 

are the only operations covered by the 

existing NSPS. 

The pipeline quality natural gas 

leaves the processing segment and 

enters the transmission segment. 

Pipelines in the natural gas transmission 

segment can be interstate pipelines that 

carry natural gas across state boundaries 

or intrastate pipelines, which transport 

the gas within a single state. While 

interstate pipelines may be of a larger 

diameter and operated at a higher 

pressure, the basic components are the 

same. To ensure that the natural gas 

flowing through any pipeline remains 

pressurized, compression of the gas is 

required periodically along the pipeline. 

This is accomplished by compressor 

stations usually placed between 40 and 

100 mile intervals along the pipeline. At 

a compressor station, the natural gas 

enters the station, where it is 

compressed by reciprocating or 

centrifugal compressors. 

In addition to the pipelines and 

compressor stations, the natural gas 

transmission segment includes 

underground storage facilities. 

Underground natural gas storage 

includes subsurface storage, which 

typically consists of depleted gas or oil 

reservoirs and salt dome caverns used 

for storing natural gas. One purpose of 

this storage is for load balancing 

(equalizing the receipt and delivery of 

natural gas). At an underground storage 

site, there are typically other processes, 


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4The Notice further states that ‘‘The 

Administrator may also concurrently develop 

standards for sources which are not on the priority 

list.’’ 44 FR at 49225. 

including compression, dehydration 

and flow measurement. 

The distribution segment is the final 

step in delivering natural gas to 

customers. The natural gas enters the 

distribution segment from delivery 

points located on interstate and 

intrastate transmission pipelines to 

business and household customers. The 

delivery point where the natural gas 

leaves the transmission segment and 

enters the distribution segment is often 

called the ‘‘citygate.’’ Typically, utilities 

take ownership of the gas at the citygate. 

Natural gas distribution systems consist 

of thousands of miles of piping, 

including mains and service pipelines 

to the customers. Distribution systems 

sometimes have compressor stations, 

although they are considerably smaller 

than transmission compressor stations. 

Distribution systems include metering 

stations, which allow distribution 

companies to monitor the natural gas in 

the system. Essentially, these metering 

stations measure the flow of gas and 

allow distribution companies to track 

natural gas as it flows through the 

system. 

Emissions can occur from a variety of 

processes and points throughout the oil 

and natural gas sector. Primarily, these 

emissions are organic compounds such 

as methane, ethane, VOC and organic 

HAP. The most common organic HAP 

are n-hexane and BTEX compounds 

(benzene, toluene, ethylbenzene and 

xylenes). Hydrogen sulfide (H2S) and 

sulfur dioxide (SO2) are emitted from 

production and processing operations 

that handle and treat ‘‘sour gas.’’ Sour 

gas is defined as natural gas with a 

maximum H2S content of 0.25 gr/100 scf 

(4ppmv) along with the presence of CO2. 

In addition, there are significant 

emissions associated with the 

reciprocating internal combustion 

engines and combustion turbines that 

power compressors throughout the oil 

and natural gas sector. However, 

emissions from internal combustion 

engines and combustion turbines are 

covered by regulations specific to 

engines and turbines and, thus, are not 

addressed in this action. 

V. Summary of Proposed Decisions and 

Actions 

Pursuant to CAA sections 111(b), 

112(d)(2), 112(d)(6) and 112(f), we are 

proposing to revise the NSPS and 

NESHAP relative to oil and gas to 

include the standards and requirements 

summarized in this section. More 

details of the rationale for these 

proposed standards and requirements 

are provided in sections VI and VII of 

this preamble. In addition, as part of 

these rationale discussions, we solicit 

public comment and data relevant to 

several issues. The comments we 

receive during the public comment 

period will help inform the rule 

development process as we work toward 

promulgating a final action. 

A. What are the proposed revisions to 

the NSPS? 

We reviewed the two NSPS that apply 

to the oil and natural gas industry. 

Based on our review, we believe that the 

requirements at 40 CFR part 60, subpart 

KKK, should be updated to reflect 

requirements in 40 CFR part 60, subpart 

VVa for controlling VOC equipment 

leaks at processing plants. We also 

believe that the requirements at 40 CFR 

part 60, subpart LLL, for controlling SO2

emissions from natural gas processing 

plants should be strengthened for 

facilities with the highest sulfur feed 

rates and the highest H2S 

concentrations. For a more detailed 

discussion, please see section VI.B.1 of 

this preamble. 

In addition, there are significant VOC 

emissions from oil and natural gas 

operations that are not covered by the 

two existing NSPS, including other 

emissions at processing plants and 

emissions from upstream production, as 

well as transmission and storage 

facilities. In the 1984 notice that listed 

source categories (including Oil and 

Natural Gas) for promulgation of NSPS, 

we noted that there were discrepancies 

between the source category names on 

the list and those in the background 

document, and we clarified our intent to 

address all sources under an industry 

heading at the same time. See 44 FR 

49222, 49224–49225.4 We, therefore, 

believe that the currently listed Oil and 

Natural Gas source category covers all 

operations in this industry (i.e., 

production, processing, transmission, 

storage and distribution). To the extent 

there are oil and gas operations not 

covered by the currently listed Oil and 

Natural Gas source category, pursuant to 

CAA section 111(b), we hereby modify 

the category list to include all 

operations in the oil and natural gas 

sector. Section 111(b) of the CAA gives 

the EPA broad authority and discretion 

to list and establish NSPS for a category 

that, in the Administrator’s judgment, 

causes or contributes significantly to air 

pollution which may reasonably be 

anticipated to endanger public health or 

welfare. Pursuant to CAA section 

111(b), we are modifying the source 

category list to include any oil and gas 

operation not covered by the current 

listing and evaluating emissions from all 

oil and gas operations at the same time. 

We are also proposing standards for 

several new oil and natural gas affected 

facilities. The proposed standards 

would apply to affected facilities that 

commence construction, reconstruction 

or modification after August 23, 2011. 

These standards, which include 

requirements for VOC, would be 

contained in a new subpart, 40 CFR part 

60, subpart OOOO. Subpart OOOO 

would incorporate 40 CFR part 60, 

subpart KKK and 40 CFR part 60, 

subpart LLL, thereby having in this one 

subpart, all standards that are applicable 

to the new and modified affected 

facilities described above. We also 

propose to amend the title of subparts 

KKK and LLL, accordingly, to apply 

only to affected facilities already subject 

to those subparts. Those operations 

would not become subject to subpart 

OOOO unless they triggered 

applicability based on new or modified 

affected facilities under subpart OOOO. 

We are proposing operational 

standards for completions of 

hydraulically fractured gas wells. Based 

on our review, we identified two 

subcategories of fractured gas wells for 

which well completions are conducted. 

For non-exploratory and nondelineation wells, the proposed 

operational standards would require 

reduced emission completion (REC), 

commonly referred to as ‘‘green 

completion,’’ in combination with pitflaring of gas not suitable for entering 

the gathering line. For exploratory and 

delineation wells (these wells generally 

are not in close proximity to a gathering 

line), we proposed an operational 

standard that would require pit flaring. 

Well completions subject to the 

standards would be limited to gas well 

completions following hydraulic 

fracturing operations. These 

completions include those conducted at 

newly drilled and fractured wells, as 

well as completions conducted 

following refracturing operations at 

various times over the life of the well. 

We have determined that a completion 

associated with refracturing performed 

at an existing well (i.e., a well existing 

prior to August 23, 2011) is considered 

a modification under CAA section 

111(a), because physical change occurs 

to the existing well resulting in 

emissions increase during the 

refracturing and completion operation. 

A detailed discussion of this 

determination is presented in the 

Technical Support Document (TSD) in 

the docket. Therefore, the proposed 

standards would apply to completions 

at new gas wells that are fractured or 


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refractured along with completions 

associated with fracturing or 

refracturing of existing gas wells. The 

modification determination and 

resultant applicability of NSPS to the 

completion operation following 

fracturing or refracturing of existing gas 

wells (i.e., wells existing before August 

23, 2011 would be limited strictly to the 

wellhead, well bore, casing and tubing, 

and any conveyance through which gas 

is vented to the atmosphere and not be 

extended beyond the wellhead to other 

ancillary components that may be at the 

well site such as existing storage 

vessels, process vessels, separators, 

dehydrators or any other components or 

apparatus. 

We are also proposing VOC standards 

to reduce emissions from gas-driven 

pneumatic devices. We are proposing 

that each pneumatic device is an 

affected facility. Accordingly, the 

proposed standards would apply to each 

newly installed pneumatic device 

(including replacement of an existing 

device). At gas processing plants, we are 

proposing a zero emission limit for each 

individual pneumatic controller. The 

proposed emission standards would 

reflect the emission level achievable 

from the use of non-gas-driven 

pneumatic controllers. At other 

locations, we are proposing a bleed limit 

of 6 standard cubic feet of gas per hour 

for an individual pneumatic controller, 

which would reflect the emission level 

achievable from the use of low bleed 

gas-driven pneumatic controllers. In 

both cases, the standards provide 

exemptions for certain applications 

based on functional considerations. 

In addition, the proposed rule would 

require measures to reduce VOC 

emissions from centrifugal and 

reciprocating compressors. As explained 

in more detail below in section VI.B.4, 

we are proposing equipment standards 

for centrifugal compressors. The 

proposed standards would require the 

use of dry seal systems. However, we 

are aware that some owners and 

operators may need to use centrifugal 

compressors with wet seals, and we are 

soliciting comment on the suitability of 

a compliance option allowing the use of 

wet seals combined with routing of 

emissions from the seal liquid through 

a closed vent system to a control device 

as an acceptable alternative to installing 

dry seals. 

Our review of reciprocating 

compressors found that piston rod 

packing wear produces fugitive 

emissions that cannot be captured and 

conveyed to a control device. As a 

result, we are proposing operational 

standards for reciprocating compressors, 

such that the proposed rule would 

require replacement of the rod packing 

based on hours of usage. The owner or 

operator of a reciprocating compressor 

affected facility would be required to 

monitor the duration (in hours) that the 

compressor is operated. When the hours 

of operation reaches 26,000 hours, the 

owner or operator would be required to 

change the rod packing immediately. 

However, to avoid unscheduled 

shutdowns when 26,000 hours is 

reached, owners and operators could 

track hours of operation such that 

packing replacement could be 

coordinated with planned maintenance 

shutdowns before hours of operation 

reached 26,000. Some operators may 

prefer to replace the rod packing on a 

fixed schedule to ensure that the hours 

of operation would not reach 26,000 

hours. We solicit comment on the 

appropriateness of a fixed replacement 

frequency and other considerations that 

would be associated with regular 

replacement. 

We are also proposing VOC standards 

for new or modified storage vessels. The 

proposed rule, which would apply to 

individual vessels, would require that 

vessels meeting certain specifications 

achieve at least 95-percent reduction in 

VOC emissions. Requirements would 

apply to vessels with a throughput of 1 

barrel of condensate per day or 20 

barrels of crude oil per day. These 

thresholds are equivalent to VOC 

emissions of about 6 tpy. 

For gas processing plants, we are 

updating the requirements for leak 

detection and repair (LDAR) to reflect 

procedures and leak thresholds 

established by 40 CFR 60, subpart VVa. 

The existing NSPS requires 40 CFR part 

60, subpart VV procedures and 

thresholds. 

For 40 CFR part 60, subpart LLL, 

which regulates SO2 emissions from 

natural gas processing plants, we 

determined that affected facilities with 

sulfur feed rate of at least 5 long tons 

per day or H2S concentration in the acid 

gas stream of at least 50 percent can 

achieve up to 99.9-percent SO2 control, 

which is greater than the existing 

standard. Therefore, we are proposing 

revision to the performance standards in 

subpart LLL as a result of this review. 

For a more detailed discussion of this 

proposed determination, please see 

section VI.B.1 of this preamble. 

We are proposing to address 

compliance requirements for periods of 

startup, shutdown and malfunction 

(SSM) for 40 CFR part 60, subpart 

OOOO. The SSM changes are discussed 

in detail in section VI.B.5 below. In 

addition, we are proposing to 

incorporate the requirements in 40 CFR 

part 60, subpart KKK and 40 CFR part 

60, subpart LLL into the new subpart 

OOOO so that all requirements 

applicable to the new and modified 

facilities would be in one subpart. This 

would simplify and streamline 

compliance efforts on the part of the oil 

and natural gas industry and could 

minimize duplication of notification, 

recordkeeping and reporting. 

B. What are the proposed decisions and 

actions related to the NESHAP? 

This section summarizes the results of 

our RTR for the Oil and Natural Gas 

Production and the Natural Gas 

Transmission and Storage source 

categories and our proposed decisions 

concerning these two 1999 NESHAP. 

1. Addressing Unregulated Emissions 

Sources 

Pursuant to CAA sections 112(d)(2) 

and (3), we are proposing MACT 

standards for subcategories of glycol 

dehydrators for which standards were 

not previously developed (hereinafter 

referred to as the ‘‘small dehydrators’’). 

In the Oil and Natural Gas Production 

source category, the subcategory 

consists of glycol dehydrators with an 

actual annual average natural gas 

flowrate less than 85,000 standard cubic 

meters per day (scmd) or actual average 

benzene emissions less than 0.9 

megagrams per year (Mg/yr). In the 

Natural Gas Transmission and Storage 

source category, the subcategory 

consists of glycol dehydrators with an 

actual annual average natural gas 

flowrate less than 283,000 scmd or 

actual average benzene emissions less 

than 0.9 Mg/yr. 

The proposed MACT standards for the 

subcategory of small dehydrators at oil 

and gas production facilities would 

require that existing affected sources 

meet a unit-specific BTEX limit of 1.10 

× 10¥4 grams BTEX/standard cubic 

meters (scm)-parts per million by 

volume (ppmv) and that new affected 

sources meet a BTEX limit of 4.66 × 

10¥6 grams BTEX/scm-ppmv. At 

natural gas transmission and storage 

affected sources, the proposed MACT 

standard for the subcategory of small 

dehydrators would require that existing 

affected sources meet a unit-specific 

BTEX emission limit of 6.42 × 10¥5

grams BTEX/scm-ppmv and that new 

affected sources meet a BTEX limit of 

1.10 × 10¥5 grams BTEX/scm-ppmv. 

We are also proposing MACT 

standards for storage vessels that are 

currently not regulated under the Oil 

and Natural Gas Production NESHAP. 

The current MACT standards apply only 

to storage vessels with the potential for 

flash emissions (PFE). As explained in 

section VII, the original MACT analysis 


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5 40 CFR 63.6(e)(1)(i) requires owners or operators 

to act according to the general duty to ‘‘operate and 

maintain any affected source, including associated 

air pollution control equipment and monitoring 

equipment, in a manner consistent with safety and 

good air pollution control practices for minimizing 

emissions.’’ This general duty to minimize is 

included in our proposed standard at 40 CFR 

63.783(b)(1). 

accounted for all storage vessels. We 

are, therefore, proposing to apply the 

current MACT standards of 95-percent 

emission reduction to every storage 

vessel at major source oil and natural 

gas production facilities. In conjunction 

with this change, we are proposing to 

amend the definition of associated 

equipment to exclude all storage 

vessels, and not just those with the PFE, 

from being considered ‘‘associated 

equipment.’’ This means that emissions 

from all storage vessels, and not just 

those from storage vessels with the PFE, 

are to be included in the major source 

determination. 

2. What are the proposed decisions and 

actions related to the risk review? 

For both the Oil and Natural Gas 

Production and the Natural Gas 

Transmission and Storage source 

categories, we find that the current 

levels of emissions allowed by the 

MACT reflect acceptable levels of risk; 

however, the level of emissions allowed 

by the alternative compliance option for 

glycol dehydrator MACT (i.e., the 

option of reducing benzene emissions to 

less than 0.9 Mg/yr in lieu of the MACT 

standard of 95-percent control) reflects 

an unacceptable level of risk. We are, 

therefore, proposing to eliminate the 0.9 

Mg/yr alternative compliance option. 

In addition, we are proposing that the 

MACT for these two oil and gas source 

categories, as revised per above, provide 

an ample margin of safety to protect 

public health and prevent adverse 

environmental effects. 

3. What are the proposed decisions and 

actions related to the technology 

reviews of the existing NESHAP? 

For both the Oil and Natural Gas 

Production and the Natural Gas 

Transmission and Storage source 

categories, we are proposing no 

revisions to the existing NESHAP 

pursuant to section 112(d)(6) of the 

CAA. 

4. What other actions are we proposing? 

We are proposing an alternative 

performance test for non-flare, 

combustion control devices. This test is 

to be conducted by the combustion 

control device manufacturer to 

demonstrate the destruction efficiency 

achieved by a specific model of 

combustion control device. This would 

allow a source to purchase a 

performance tested device for 

installation at their site without being 

required to conduct a site-specific 

performance test. A definition for 

‘‘flare’’ is being proposed in the 

NESHAP to clarify which combustion 

control devices fall under the 

manufacturers’ performance testing 

alternative, and to clarify which devices 

must be performance tested. 

We are also proposing to: Revise the 

parametric monitoring calibration 

provisions; require periodic 

performance testing where applicable; 

remove the allowance of a design 

analysis for all control devices other 

than condensers; remove the 

requirement for a minimum residence 

time for an enclosed combustion device; 

and add recordkeeping and reporting 

requirements to document carbon 

replacement intervals. These changes 

are being proposed to bring the 

NESHAP up-to-date based on what we 

have learned regarding control devices 

and compliance since the original 

promulgation date. 

In addition, we are proposing the 

elimination of the SSM exemption in 

the Oil and Natural Gas Production and 

the Natural Gas Transmission and 

Storage NESHAP. As discussed in more 

detail below in section VII, consistent 

with Sierra Club v. EPA, 551 F.3d 1019 

(D.C. Cir. 2010), the EPA is proposing 

that the established standards in these 

two NESHAP apply at all times. We are 

proposing to revise Table 2 to both 40 

CFR part 63, subpart HH and 40 CFR 

part 63, subpart HHH to indicate that 

certain 40 CFR part 63 general 

provisions relative to SSM do not apply, 

including: 40 CFR 63.6 (e)(1)(i) 5 and 

(ii), 40 CFR 63.6(e)(3) (SSM plan 

requirement), 40 CFR 63.6(f)(1); 40 CFR 

63.7(e)(1), 40 CFR 63.8(c)(1)(i) and (iii), 

and the last sentence of 40 CFR 

63.8(d)(3); 40 CFR 63.10(b)(2)(i),(ii), (iv) 

and (v); 40 CFR 63.10(c)(10), (11) and 

(15); and 40 CFR 63.10(d)(5). We are 

also proposing to: (1) Revise 40 CFR 

63.771(d)(4)(i) and 40 CFR 

63.1281(d)(4)(i) regarding operation of 

the control device to be consistent with 

the SSM compliance requirements; and 

(2) revise the SSM-associated reporting 

and recordkeeping requirements in 40 

CFR 63.774, 40 CFR 63.775, 40 CFR 

63.1284 and 40 CFR 63.1285 to require 

reporting and recordkeeping for periods 

of malfunction. In addition, as 

explained below, we are proposing to 

add an affirmative defense to civil 

penalties for exceedances of emission 

limits caused by malfunctions, as well 

as criteria for establishing the 

affirmative defense. 

The EPA has attempted to ensure that 

we have neither overlooked nor failed to 

propose to remove from the existing text 

any provisions that are inappropriate, 

unnecessary or redundant in the 

absence of the SSM exemption, nor 

included any such provisions in the 

proposed new regulatory language. We 

are specifically seeking comment on 

whether there are any such provisions 

that we have inadvertently overlooked 

or incorporated. 

We are also revising the applicability 

provisions of 40 CFR part 63, subpart 

HH to clarify requirements regarding 

PTE determination and the scope of a 

facility subject to subpart HH. Lastly, we 

are proposing several editorial 

corrections and plain language revisions 

to improve these rules. 

C. What are the proposed notification, 

recordkeeping and reporting 

requirements for this proposed action? 

1. What are the proposed notification, 

recordkeeping and reporting 

requirements for the proposed NSPS? 

The proposed 40 CFR part 60, subpart 

OOOO includes new requirements for 

several operations for which there are 

no existing Federal standards. Most 

notably, as discussed in sections V.A 

and VI.B of this preamble, the proposed 

NSPS will cover completions and 

recompletions of hydraulically fractured 

gas wells. We estimate that over 20,000 

completions and recompletions 

annually will be subject to the proposed 

requirements. Given the number of 

these operations, we believe that 

notification and reporting must be 

streamlined to the extent possible to 

minimize undue burden on owners and 

operators, as well as state, local and 

tribal agencies. In section V.D of this 

preamble, we discuss some innovative 

implementation approaches being 

considered and seek comment on these 

and other potential methods of 

streamlining notification and reporting 

for well completions covered by the 

proposed rule. 

Owners or operators are required to 

submit initial notifications and annual 

reports, and to retain records to assist in 

documenting that they are complying 

with the provisions of the NSPS. These 

notification, recordkeeping and 

reporting activities include both 

requirements of the 40 CFR part 60 

General Provisions, as well as 

requirements specific to 40 CFR part 60, 

subpart OOOO. 

Owners or operators of affected 

facilities (except for pneumatic 

controller and gas wellhead affected 


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sources) must submit an initial 

notification within 1 year after 

becoming subject to 40 CFR part 60, 

subpart OOOO or by 1 year after the 

publication of the final rule in the 

Federal Register, whichever is later. For 

pneumatic controllers, owners and 

operators are not required to submit an 

initial notification, but instead are 

required to report the installation of 

these affected facilities in their facility’s 

annual report. Owners or operators of 

wellhead affected facilities (well 

completions) would also be required to 

submit a 30-day advance notification of 

each well completion subject to the 

NSPS. In addition, annual reports are 

due 1 year after initial startup date for 

your affected facility or 1 year after the 

date of publication of the final rule in 

the Federal Register, whichever is later. 

The notification and annual reports 

must include information on all affected 

facilities owned or operated that were 

new, modified or reconstructed sources 

during the reporting period. A single 

report may be submitted covering 

multiple affected facilities, provided 

that the report contains all the 

information required by 40 CFR 

60.5420(b). This information includes 

general information on the facility (i.e., 

company name and address, etc.), as 

well as information specific to 

individual affected facilities. 

For wellhead affected facilities, this 

information includes details of each 

well completion during the period, 

including duration of periods of gas 

recovery, flaring and venting. For 

centrifugal compressor affected 

facilities, information includes 

documentation that the compressor is 

fitted with dry seals. For reciprocating 

compressors, information includes the 

cumulative hours of operation of each 

compressor and records of rod packing 

replacement. 

Information for pneumatic device 

affected facilities includes location and 

manufacturer specifications of each 

pneumatic controller installed during 

the period and documentation that 

supports any exemption claimed 

allowing use of high bleed controllers. 

For controllers installed at gas 

processing plants, the owner or operator 

would document the use of non-gas 

driven devices. For controllers installed 

in locations other than at gas processing 

plants, owners or operators would 

provide manufacturer’s specifications 

that document bleed rate not exceeding 

6 cubic feet per hour. 

For storage vessel affected facilities, 

required report information includes 

information that documents control 

device compliance, if applicable. For 

vessels with throughputs below 1 barrel 

of condensate per day and 21 barrels of 

crude oil per day, required information 

also includes calculations or other 

documentation of the throughput. For 

onshore gas processing plants, semiannual reports are required, and include 

information on number of pressure 

relief devices, number of pressure relief 

devices for which leaks were detected 

and pressure relief devices for which 

leaks were not repaired, as required in 

40 CFR 60.5396 of subpart OOOO. 

Records must be retained for 5 years 

and generally consist of the same 

information required in the initial 

notification and annual and semiannual 

reports. 

2. What are the proposed amendments 

to notification, recordkeeping and 

reporting requirements for the 

NESHAP? 

We are proposing to revise certain 

recordkeeping requirements of 40 CFR 

part 63, subpart HH and 40 CFR part 63, 

subpart HHH. Specifically, we are 

proposing that facilities using carbon 

adsorbers as a control device keep 

records of their carbon replacement 

schedule and records for each carbon 

replacement. In addition, owners and 

operators are required to keep records of 

the occurrence and duration of each 

malfunction or operation of the air 

pollution control equipment and 

monitoring equipment. 

In addition, in conjunction with the 

proposed MACT standards for small 

glycol dehydration units and storage 

vessels that do not have the PFE in the 

proposed amendment to 40 CFR part 63, 

subpart HH, we are proposing that 

owners and operators of affected small 

glycol dehydration units and storage 

vessels submit an initial notification 

within 1 year after becoming subject to 

subpart HH or by 1 year after the 

publication of the final rule in the 

Federal Register, whichever is later. 

Similarly, in conjunction with the 

proposed MACT standards for small 

glycol dehydration units in the 

proposed 40 CFR part 63, subpart HHH 

amendments, we are proposing that 

owners and operators of small glycol 

dehydration units submit an initial 

notification within 1 year after 

becoming subject to subpart HHH or by 

1 year after the publication of the final 

rule in the Federal Register, whichever 

is later. Affected sources under either 40 

CFR part 63, subpart HH or subpart 

HHH that plan to be area sources by the 

compliance dates will be required to 

submit a notification describing their 

schedule for the actions planned to 

achieve area source status. 

The proposed amendments to the 

NESHAP also include additional 

requirements for the contents of the 

periodic reports. For both 40 CFR part 

63, subpart HH and 40 CFR part 63, 

subpart HHH, we are proposing that the 

periodic reports also include periodic 

test results and information regarding 

any carbon replacement events that 

occurred during the reporting period. 

3. How is information submitted using 

the Electronic Reporting Tool (ERT)? 

Performance test data are an 

important source of information that the 

EPA uses in compliance determinations, 

developing and reviewing standards, 

emission factor development, annual 

emission rate determinations and other 

purposes. In these activities, the EPA 

has found it ineffective and time 

consuming, not only for owners and 

operators, but also for regulatory 

agencies, to locate, collect and submit 

performance test data because of varied 

locations for data storage and varied 

data storage methods. In recent years, 

though, stack testing firms have 

typically collected performance test data 

in electronic format, making it possible 

to move to an electronic data submittal 

system that would increase the ease and 

efficiency of data submittal and improve 

data accessibility. 

Through this proposal, the EPA is 

taking a step to increase the ease and 

efficiency of data submittal and improve 

data accessibility. Specifically, the EPA 

is proposing that owners and operators 

of oil and natural gas sector facilities 

submit electronic copies of required 

performance test reports to the EPA’s 

WebFIRE database. The WebFIRE 

database was constructed to store 

performance test data for use in 

developing emission factors. A 

description of the WebFIRE database is 

available at http://cfpub.epa.gov/ 

oarweb/index.cfm?action=fire.main. 

As proposed above, data entry would 

be through an electronic emissions test 

report structure called the Electronic 

Reporting Tool (ERT). The ERT will be 

able to transmit the electronic report 

through the EPA’s Central Data 

Exchange network for storage in the 

WebFIRE database making submittal of 

data very straightforward and easy. A 

description of the ERT can be found at 

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

ert_tool.html. 

The proposal to submit performance 

test data electronically to the EPA 

would apply only to those performance 

tests conducted using test methods that 

will be supported by the ERT. The ERT 

contains a specific electronic data entry 

form for most of the commonly used 

EPA reference methods. A listing of the 

pollutants and test methods supported 

by the ERT is available at http:// 


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

We believe that industry would benefit 

from this proposed approach to 

electronic data submittal. Having these 

data, the EPA would be able to develop 

improved emission factors, make fewer 

information requests, and promulgate 

better regulations. 

One major advantage of the proposed 

submittal of performance test data 

through the ERT is a standardized 

method to compile and store much of 

the documentation required to be 

reported by this rule. Another advantage 

is that the ERT clearly states testing 

information that would be required. 

Another important benefit of submitting 

these data to the EPA at the time the 

source test is conducted is that it should 

substantially reduce the effort involved 

in data collection activities in the 

future. When the EPA has performance 

test data in hand, there will likely be 

fewer or less substantial data collection 

requests in conjunction with 

prospective required residual risk 

assessments or technology reviews. This 

would result in a reduced burden on 

both affected facilities (in terms of 

reduced manpower to respond to data 

collection requests) and the EPA (in 

terms of preparing and distributing data 

collection requests and assessing the 

results). 

State, local and tribal agencies could 

also benefit from more streamlined and 

accurate review of electronic data 

submitted to them. The ERT would 

allow for an electronic review process 

rather than a manual data assessment 

making review and evaluation of the 

source provided data and calculations 

easier and more efficient. Finally, 

another benefit of the proposed data 

submittal to WebFIRE electronically is 

that these data would greatly improve 

the overall quality of existing and new 

emissions factors by supplementing the 

pool of emissions test data for 

establishing emissions factors and by 

ensuring that the factors are more 

representative of current industry 

operational procedures. A common 

complaint heard from industry and 

regulators is that emission factors are 

outdated or not representative of a 

particular source category. With timely 

receipt and incorporation of data from 

most performance tests, the EPA would 

be able to ensure that emission factors, 

when updated, represent the most 

current range of operational practices. In 

summary, in addition to supporting 

regulation development, control strategy 

development and other air pollution 

control activities having an electronic 

database populated with performance 

test data would save industry, state, 

local, tribal agencies and the EPA 

significant time, money and effort while 

also improving the quality of emission 

inventories and, as a result, air quality 

regulations. 

D. What are the innovative compliance 

approaches being considered? 

Given the potential number and 

diversity of sources affected by this 

action, we are exploring optional 

approaches to provide the regulated 

community, the regulators and the 

public a more effective mechanism that 

maximizes compliance and 

transparency while minimizing burden. 

Under a traditional approach, owners 

or operators would provide notifications 

and keep records of information 

required by the NSPS. In addition, they 

would certify compliance with the 

NSPS as part of a required annual report 

that would include compliance-related 

information, such as details of each well 

completion event and information 

documenting compliance with other 

requirements of the NSPS. The EPA, 

state or local agency would then 

physically inspect the affected facilities 

and/or audit the records retained by the 

owner or operator. As an alternative to 

the traditional approach, we are seeking 

an innovative way to provide for more 

transparency to the public and less 

burden on the regulatory agencies and 

owners and operators, especially as it 

relates to modification of existing 

sources through recompletions of 

hydraulically fractured gas wells. These 

innovative approaches would provide 

compliance assurance in light of the 

absence of requirements for CAA title V 

permitting of non-major sources. 

Section V.E of this preamble discusses 

permitting implications associated with 

the NSPS and presents a proposed 

rationale for exempting non-major 

sources subject to the NSPS from title V 

permitting requirements. As discussed 

in sections V.A, V.C and VI.B of this 

preamble, the proposed NSPS will cover 

completions and recompletions of 

hydraulically fractured gas wells. We 

estimate that over 20,000 completions 

and recompletions annually will be 

subject to the proposed requirements. 

As a result, we believe that notification 

and reporting associated with well 

completions must be streamlined to the 

extent possible to minimize undue 

burden on owners and operators, as well 

as state, local and tribal agencies. 

Though the requirements being 

proposed here are based on the 

traditional approach to compliance and 

do not include specific regulatory 

provisions for innovative compliance 

tools, we have included discussions 

below that describe how some of these 

optional tools could work, and we will 

consider providing for such options in 

the final action. Further, we request 

comments and suggestions on all 

aspects of the innovative compliance 

approaches discussed below and how 

they may be implemented 

appropriately. We are seeking comment 

regarding the scope of application of 

one or more of these approaches, i.e., 

which provisions of the standards being 

proposed here would be suitable for 

specific compliance approaches, and 

whether the approaches should be 

alternatives to the requirements in the 

regulations. 

The guiding principles we are 

following in considering these 

approaches to compliance are: (1) 

Simplicity and ease of understanding 

and implementation; (2) transparency 

and public accessibility; (3) electronic 

implementation where appropriate; and 

(4) encouragement of compliance by 

making compliance easier than 

noncompliance. Below are some tools 

that, when used in tandem with 

emissions limits and operational 

standards, the Agency believes could 

both assure compliance and 

transparency, while minimizing burden 

on affected sources and regulatory 

agencies. 

1. Registration of Wells and Advance 

Notification of Planned Completions 

Although the proposed NSPS will not 

require approval to drill or complete 

wells, it is important that regulatory 

agencies know when completions of 

hydraulically fractured wells are to be 

performed. Notification should occur 

sufficiently in advance to allow for 

inspections or audits to certify or verify 

that the operator will have in place and 

use the appropriate controls during the 

completion. To that end, the proposed 

NSPS requires a 30-day advance 

notification of each completion or 

recompletion of a hydraulically 

fractured gas well. The advance 

notification would require that owners 

or operators provide the anticipated 

date of the completion, the geographic 

coordinates of the well and identifying 

information concerning the owner or 

operator and responsible company 

official. We believe this notification 

requirement serves as the registration 

requirement and could be streamlined 

through optional electronic reporting 

with web-based public access or other 

methods. We seek comment on potential 

methodologies that would minimize 

burden on operators, while providing 

timely and useful information for 

regulators and the public. We also 

solicit comment on provisions for a 

follow-up notification one or two days 

before an impending completion via 


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telephone or by electronic means, since 

it is difficult to predict exactly when a 

well will be ready for completion a 

month in advance. However, we would 

expect an owner or operator to provide 

the follow-up notification only in cases 

where the completion date was 

expected to deviate from the original 

date provided. We ask for suggestions 

regarding how much advance 

notification is needed and the most 

effective method of providing sufficient 

and accurate advance notification of 

well completions. 

2. Third Party Verification 

To complement the annual 

compliance certification required under 

the proposed NSPS, we are considering 

and seeking comment on the potential 

use of third party verification to assure 

compliance. Since the emission sources 

in the oil and natural gas sector, 

especially well completions, are widely 

geographically dispersed (often in very 

remote locations), compliance assurance 

can be very difficult and burdensome 

for state, local and tribal agencies and 

EPA permitting staff, inspectors and 

compliance officers. Additionally, we 

believe that verification of the data 

collection, compilation and calculations 

by an independent and impartial third 

party could facilitate the demonstration 

of compliance for the public. 

Verification of emissions data can also 

be beneficial to owners and operators by 

providing certainty of compliance 

status. 

As mentioned above, notification and 

reporting requirements associated with 

well completions are likely applications 

for third party verification used in 

tandem with the required annual 

compliance certification. The third 

party verification program could be 

used in a variety of ways to ease 

regulatory burden on the owners and 

operators and to leverage compliance 

assurance efforts of the EPA and state, 

local and tribal agencies. The third party 

agent could serve as a clearinghouse for 

notifications, records and annual 

compliance certifications submitted by 

owners and operators. This would 

provide online access to completion 

information by regulatory agencies and 

the public. Having notifications 

submitted to the clearinghouse would 

relieve state, local and tribal agencies of 

the burden of receiving thousands of 

paper or e-mail well completion 

notifications each year, yet still provide 

them quick access to the information. 

Using a third party agent, it is possible 

that notifications of well completions 

could be submitted with an advance 

period much less than 30 days that 

could make a 2 day follow-up 

notification unnecessary. The 

clearinghouse could also house 

information on past completions and 

copies of compliance certifications. We 

seek comment on whether annual 

reports for well completions would be 

needed if a suitable third party 

verification program was in place and 

already housed that same information. 

We also solicit comment on the range of 

potential activities the third party 

verification program could handle with 

regard to well completions. 

In this proposed action, there are also 

provisions for applying third party 

verification to the required electronic 

reporting using the ERT (see section 

V.C.3 above for a discussion of the ERT). 

As stated above, all sources must use 

the ERT to submit all performance test 

reports (required in 40 CFR parts 60, 61 

and 63) to the EPA. There is an option 

in the ERT for state, local and tribal 

agencies to review and verify that the 

information submitted to the EPA is 

truthful, accurate and complete. Third 

party verifiers could be contractors or 

other personnel familiar with oil and 

natural gas exploration and production. 

We are seeking comment on appropriate 

third party reviewers and qualifications 

and registration requirements under 

such a program. We want to state clearly 

here that third party verification would 

not supersede or substitute for 

inspections or audit of data and 

information by state, local and tribal 

agencies and the EPA. 

Potential issues with third party 

verification include costs incurred by 

industry and approval of third party 

verifiers. The cost of third party 

verification would be borne by the 

affected industries. We are seeking 

comment on whether third party 

verification paid for by industry would 

result in impartial, accurate and 

complete data information. The EPA, 

working with state, local and tribal 

agencies and industry, would expect to 

develop guidance for third party 

verifiers. We are seeking comment on 

whether or not the EPA should approve 

third party verifiers. 

3. Electronic Reporting Using Existing 

Mechanisms 

The proposed 40 CFR part 60, subpart 

OOOO and final Greenhouse Gas (GHG) 

Mandatory Reporting Rule, 40 CFR part 

98, subpart W, provide details on flare 

and vented emission sources and how to 

estimate their emissions. We solicit 

comment on requiring sources to 

electronically submit their emissions 

data for the oil and gas rules proposed 

here. The EPA’s Electronic Greenhouse 

Gas Reporting Tool (e-GGRT) for 40 CFR 

part 98, subpart W, while used to report 

emissions at the emissions source level 

(e.g., well completions, well unloading, 

compressors, gas plant leaks, etc.), will 

aggregate emissions at the basin level for 

e-reporting purposes. As a result, it may 

be difficult to merge reporting under 

NSPS subpart OOOO with GHG 

Reporting Rule subpart W methane 

reporting, especially if manual reporting 

is used. However, since the operator 

would have these emissions details at 

the individual well level (because that 

will be how they would develop their 

basin-wide estimates), we do not believe 

it would be a significant burden to 

require owners or operators to report the 

data they already have for subpart W in 

an ERT for NSPS and NESHAP 

compliance purposes. However, if the eGGRT is not structured to provide for 

reporting of other pollutants besides 

GHG (e.g., VOC and HAP), then there 

may be some modification of the 

database required to accommodate the 

other pollutants. 

4. Provisions for Encouraging Innovative 

Technology 

The oil and natural gas industry has 

a long history of innovation in 

developing new exploration and 

production methods, along with 

techniques to minimize product losses 

and reduce adverse environmental 

impacts. These efforts are often 

undertaken with tremendous amounts 

of research, including pilot applications 

at operating facilities in the field. 

Absent regulation, these developmental 

activities, some of which ultimately are 

not successful, can proceed without risk 

of violation of any standards. However, 

as more emission sources in this source 

category are covered by regulation, as in 

the case of the action being proposed 

here, there likely will be situations 

where innovation and development of 

new control techniques potentially 

could be stifled by risk of violation. 

We believe it is important to facilitate, 

not hinder, innovation and continued 

development of new technology that can 

result in enhanced environmental 

performance of facilities and sources 

affected by the EPA’s regulations. 

However, any approaches to 

accommodate technology development 

must be designed and implemented in 

accordance with the CAA and other 

statutes. We seek comment on 

approaches that may be suitable for 

allowing temporary field testing of 

technology in development. These 

approaches could include not only 

established procedures under the CAA 

and its implementing regulations, but 

new ways to apply or interpret these 

provisions to avoid impeding 


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6Withdrawal of Source Determinations for Oil 

and Gas Industries, September 22, 2009. This memo 

continues to articulate the Agency’s interpretation 

for major NSR and title V permitting of oil and gas 

sources. 

7CAA section 502(a) prohibits title V exemption 

for any major source, which is defined in CAA 

section 501(2) and 40 CFR 70.2. 

8The legislative history of section 502(a) suggests 

that EPA should not grant title V exemptions where 

doing so would adversely affect public health, 

welfare or the environment. (See Chafee-Baucus 

Statement of Senate Managers, Environment and 

Natural Resources Policy Division 1990 CAA Leg. 

Hist. 905, Compiled November 1993.) 

innovation while remaining 

environmentally responsible and legal. 

E. How does the NSPS relate to 

permitting of sources? 

1. How does this action affect permitting 

requirements? 

The proposed rules do not change the 

Federal requirements for determining 

whether oil and gas sources are major 

sources for purposes of nonattainment 

major New Source Review (NSR), 

prevention of significant deterioration, 

CAA title V, or HAP major sources 

pursuant to CAA section 112. 

Specifically, if an owner or operator is 

not currently required to get a major 

NSR or title V permit for oil and gas 

sources, including well completions, it 

would not be required to get a major 

NSR or title V permit as a result of these 

proposed standards. EPA-approved state 

and local major source permitting 

programs would not be affected. That is, 

state and local agencies with EPAapproved programs will still make caseby-case major source determinations for 

purposes of major NSR and title V, 

relying on the regulatory criteria, as 

explained in the McCarthy Memo.6

Consistent with the McCarthy Memo, 

whether or not a permitting authority 

should aggregate two or more pollutantemitting activities into a single major 

stationary source for purposes of NSR 

and title V remains a case-by-case 

decision in which permitting authorities 

retain the discretion to consider the 

factors relevant to the specific 

circumstances of the permitted 

activities. 

In addition, the proposed standards 

would not change the requirements for 

determining whether oil and gas sources 

are subject to minor NSR. Nor would the 

proposed standards affect existing EPAapproved state and local minor NSR 

rules, as well as policies and practices 

implementing those rules. Many state 

and local agencies have already adopted 

minor NSR permitting programs that 

provide for control of emissions from 

relatively small emission sources, 

including various pieces of equipment 

used in oil and gas fields. State and 

local agencies would be able to continue 

to use any EPA-approved General 

Permits, Permits by Rule, and other 

similar streamlining mechanisms to 

permit oil and gas sources such as wells. 

We recently promulgated the final 

Tribal Minor NSR rules for use in 

issuing minor issue permits on tribal 

lands, where many oil and gas sources 

are located. 

The proposed standards will lead to 

better control of and reduced emissions 

from oil and gas production, gas 

processing and transmission and 

storage, including wells. In some 

instances, we anticipate that complying 

with the NSPS would reduce emissions 

from these smaller sources to below the 

minor source applicability thresholds. 

In those cases, sources that would 

otherwise have been subject to minor 

NSR would not need to get minor NSR 

permits as a result of being subject to 

the NSPS. Accordingly, the number of 

minor NSR permits, as well as the 

Agency resources needed to issue them, 

would be reduced. 

We expect the emission reductions 

achieved from the proposed standards 

to significantly improve ozone 

nonattainment problems in areas where 

oil and gas production occurs. Strategies 

for attaining and maintaining the 

national ambient air quality standards 

(NAAQS) are a function of SIP (or, in 

some instances, Federal Implementation 

Plans and Tribal Implementation Plans) 

pursuant to CAA section 110. In 

developing plans to attain and maintain 

the NAAQS, EPA works with state, local 

or Tribal agencies to account for growth 

and develop overall control strategies 

that address existing and expected 

emissions. The reductions achieved by 

the standards will make it easier for 

state and local agencies to plan for and 

to attain and maintain the ozone 

NAAQS. 

2. How does this action affect 

applicability of CAA title V? 

Under section 502(a) of the CAA, the 

EPA may exempt one or more non-major 

sources 7 subject to CAA section 111 

(NSPS) standards from the requirements 

of title V if the EPA finds that 

compliance with such requirements is 

‘‘impracticable, infeasible, or 

unnecessarily burdensome’’ on such 

sources. The EPA determine whether to 

exempt a non-major source from title V 

at the time we issue the relevant CAA 

section 111 standards (40 CFR 

70.3(b)(2)). We are proposing in this 

action to exempt from the requirements 

of title V non-major sources that would 

be subject to the proposed NSPS for 

well completions, pneumatic devices, 

compressors, and/or storage vessels. 

These non-major sources (hereinafter 

referred to as the ‘‘oil and gas NSPS 

non-major sources’’) would not be 

required to obtain title V permits solely 

as a result of being subject to one or 

more of the proposed NSPS identified 

above (hereinafter referred to as the 

‘‘proposed NSPS’’); however, if they 

were otherwise required to obtain title 

V permits, such requirement(s) would 

not be affected by the proposed 

exemption. 

Consistent with the statute, the EPA 

believes that compliance with title V 

permitting is ‘‘unnecessarily 

burdensome’’ for the oil and gas NSPS 

non-major sources. The EPA’s inquiry 

into whether this criterion was satisfied 

is based primarily upon consideration of 

the following four factors: (1) Whether 

title V would result in significant 

improvements to the compliance 

requirements that we are proposing for 

the oil and gas NSPS affected non-major 

sources; (2) whether title V permitting 

would impose a significant burden on 

these non-major sources and whether 

that burden would be aggravated by any 

difficulty these sources may have in 

obtaining assistance from permitting 

agencies; (3) whether the costs of title V 

permitting for these non-major sources 

would be justified, taking into 

consideration any potential gains in 

compliance likely to occur for such 

sources; and (4) whether there are 

implementation and enforcement 

programs in place that are sufficient to 

assure compliance with the proposed 

Oil and Natural Gas NSPS without 

relying on title V permits. Not all of the 

four factors must weigh in favor of an 

exemption. See 70 FR 75320, 75323 

(Title V Exemption Rule). Instead, the 

factors are to be considered in 

combination and the EPA determines 

whether the factors, taken together, 

support an exemption from title V for 

the oil and gas non-major sources. 

Additionally, consistent with the 

guidance provided by the legislative 

history of CAA section 502(a),8 we 

considered whether exempting the Oil 

and Natural Gas NSPS non-major 

sources would adversely affect public 

health, welfare or the environment. The 

first factor is whether title V would 

result in significant improvements to 

the compliance requirements in the 

proposed NSPS. A finding that title V 

would not result in significant 

improvements to the compliance 

requirements in the proposed NSPS 

would support a conclusion that title V 

permitting is ‘‘unnecessary’’ for nonVerDate Mar<15>2010 17:12 Aug 22, 2011 Jkt 223001 PO 00000 Frm 00015 Fmt 4701 Sfmt 4702 E:\FR\FM\23AUP2.SGM 23AUP2

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9The proposed numeric standards for pneumatic 

controllers reflect the use of specific equipment 

(either non-gas driven device or low-bleed device). 

major sources subject to the Oil and 

Natural Gas Production NSPS. 

One way that title V may improve 

compliance is by requiring monitoring 

(including recordkeeping designed to 

serve as monitoring) to assure 

compliance with permit terms and 

conditions reflecting the emission 

limitations and control technology 

requirements imposed in the standard. 

See 40 CFR 70.6(c)(1) and 40 CFR 

71.6(c)(1). The ‘‘periodic monitoring’’ 

provisions of 40 CFR 70.6(a)(3)(i)(B) and 

40 CFR 71.6(a)(3)(i)(B) require new 

monitoring to be added to the permit 

when the underlying standard does not 

already require ‘‘periodic testing or 

instrumental or noninstrumental 

monitoring (which may consist of 

recordkeeping designed to serve as 

monitoring).’’ In addition, title V 

imposes a number of recordkeeping and 

reporting requirements that may be 

important for assuring compliance. 

These include requirements for a 

monitoring report at least every 6 

months, prompt reports of deviations, 

and an annual compliance certification. 

See 40 CFR 70.6(a)(3) and 40 CFR 

71.6(a)(3), 40 CFR 70.6(c)(1) and 40 CFR 

71.6(c)(1), and 40 CFR 70.6(c)(5) and 40 

CFR 71.6(c)(5). To determine whether 

title V permits would add significant 

compliance requirements to the 

proposed NSPS, we compared the title 

V monitoring, recordkeeping and 

reporting requirements mentioned 

above to those requirements proposed 

for the Oil and Natural Gas NSPS 

affected facilities. 

For wellhead affected facilities (well 

completions), the proposed NSPS would 

require (1) 30-day advance notification 

of each well completion to be 

performed; (2) noninstrumental 

monitoring, which is achieved through 

documentation and recordkeeping of 

procedures followed during each 

completion, including total duration of 

the completion event, amount of time 

gas is recovered using reduced emission 

completion techniques, amount of time 

gas is combusted, amount of time gas is 

vented to the atmosphere and 

justification for periods when gas is 

combusted or vented rather than being 

recovered; (3) reports of cases where 

well completions were not performed in 

compliance with the NSPS; (4) annual 

reports that document all completions 

performed during the reporting period 

(a single report may be used to 

document multiple completions 

conducted by a single owner or operator 

during the reporting period); and (5) 

annual compliance certifications 

submitted with the annual report. 

These monitoring, recordkeeping and 

reporting requirements in the proposed 

NSPS for well completions are sufficient 

to ensure that the Administrator, the 

state, local and tribal agencies and the 

public are aware of completion events 

before they are performed to provide 

opportunity for inspection. Sufficient 

documentation would also be required 

to be retained and reported to the 

Administrator to assure compliance 

with the NSPS for well completions. In 

light of the above, we have determined 

that additional monitoring through title 

V is not needed and that the monitoring, 

recordkeeping and reporting 

requirements described above are 

sufficient to assure compliance with the 

proposed requirements for well 

completions. 

With respect to storage vessels, the 

proposed NSPS would require 95- 

percent control of VOC emissions. The 

proposed standard could be met by a 

vapor recovery unit, a flare control 

device or other control device. The 

proposed NSPS would require an initial 

performance test followed by 

continuous monitoring of the control 

device used to meet the 95-percent 

control. We believe that the monitoring 

requirements described above are 

sufficient to assure compliance with the 

proposed NSPS for storage vessels and, 

therefore, additional monitoring through 

title V is not needed. In addition to 

monitoring, as part of the first factor, we 

have considered the extent to which 

title V could potentially enhance 

compliance through recordkeeping or 

reporting requirements. The proposed 

NSPS would require (1) construction, 

startup and modification notifications, 

as required by 40 CFR 60.7(a); and (2) 

annual reports that identify all storage 

vessel affected facilities of the owner or 

operator and documentation of periods 

of non-compliance. The proposed NSPS 

would also require records documenting 

liquid throughput of condensate or 

crude oil (to determine applicability), as 

provided for in the proposed rule. 

Recordkeeping would also include 

records of the initial performance test 

and other information that document 

compliance with applicable emission 

limit. These requirements are similar to 

those under title V. In light of the above, 

we believe that the monitoring, 

recordkeeping and reporting 

requirements described above are 

sufficient to assure compliance with the 

proposed NSPS for storage vessels. 

For pneumatic controllers, centrifugal 

compressors and reciprocating 

compressors, the proposed NSPS are in 

the form of operational, work practice or 

equipment standards.9 For each of these 

affected facilities, the proposed NSPS 

would require: (1) Construction, startup 

and modification notifications, as 

required by 40 CFR 60.7(a); (2) annual 

reports; (3) for each pneumatic 

controller installed or modified 

(including replacement of an existing 

controller), records of location and date 

of installation and documentation that 

each controller emits no more than the 

applicable emission limit or is exempt 

(with rationale for the exemption); (4) 

for each centrifugal compressor, records 

that document that each new or 

modified compressor is equipped with 

dry seals; and (5) for each new or 

modified reciprocating compressor, 

records of rod packing replacement, 

including elapsed operating hours since 

the previous rod packing installation. 

For these other affected sources 

described above, the proposed NSPS 

provide monitoring in the form of 

recordkeeping (as described above) that 

would assure compliance with the 

proposed operational, work practice or 

equipment standards. Monitoring by 

means other than recordkeeping would 

not be practical or appropriate for these 

standards. Records are required to 

ensure that these standards and 

practices are followed. We believe that 

the monitoring, recordkeeping and 

reporting requirements described above 

are sufficient to assure compliance with 

the proposed NSPS for pneumatic 

controllers and compressors. 

We acknowledge that title V might 

provide for additional compliance 

requirements for these non-major 

sources, but we have determined, as 

explained above, that the monitoring, 

recordkeeping and reporting 

requirements in this proposed NSPS are 

sufficient to assure compliance with the 

proposed standards for well 

completions, storage vessels, pneumatic 

controllers and compressors. Further, 

given the nature of some of the 

operations and the types of the 

requirements at issue, the additional 

compliance requirements under title V 

would not significantly improve the 

compliance requirements in this 

proposed NSPS. For instance, well 

completions occur over a very short 

period (generally 3 to 10 days), and the 

proposed NSPS for pneumatic 

controllers and centrifugal compressors 

can be met by simply installing the 

equipment that meet the proposed 

emission limit; therefore, the semiannual reporting requirement under title 

V would not improve compliance with 


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these proposed NSPS and, in fact, may 

seem inappropriate for such short term 

operations. 

For the reasons stated above, we 

believe that title V would not result in 

significant improvements to the 

compliance requirements that are 

provided in this proposed NSPS. 

Therefore, the first factor supports a 

conclusion that title V permitting is 

‘‘unnecessary’’ for non-major sources 

subject to the Oil and Natural Gas NSPS. 

The second factor we considered is 

whether title V permitting would 

impose significant burdens on the oil 

and natural gas NSPS non-major sources 

and whether that burden would be 

aggravated by any difficulty these 

sources may have in obtaining 

assistance from permitting agencies. 

Subjecting any source to title V 

permitting imposes certain burdens and 

costs that do not exist outside of the title 

V program. EPA estimated that the 

average cost of obtaining and complying 

with a title V permit was $65,700 per 

source for a 5-year permit period, 

including fees. See Information 

Collection Request (ICR) for Part 70 

Operating Permit Regulations, January 

2007, EPA ICR Number 1587.07. EPA 

does not have specific estimates for the 

burdens and costs of permitting the oil 

and gas NSPS non-major sources; 

however, there are certain activities 

associated with the 40 CFR part 70 and 

40 CFR part 71 rules. These activities 

are mandatory and impose burdens on 

any facility subject to title V. They 

include reading and understanding 

permit program regulations; obtaining 

and understanding permit application 

forms; answering follow-up questions 

from permitting authorities after the 

application is submitted; reviewing and 

understanding the permit; collecting 

records; preparing and submitting 

monitoring reports; preparing and 

submitting prompt deviation reports, as 

defined by the state, which may include 

a combination of written, verbal and 

other communication methods; 

collecting information, preparing and 

submitting the annual compliance 

certification; preparing applications for 

permit revisions every 5 years; and, as 

needed, preparing and submitting 

applications for permit revisions. In 

addition, although not required by the 

permit rules, many sources obtain the 

contractual services of consultants to 

help them understand and meet the 

permitting program’s requirements. The 

ICR for 40 CFR part 70 provides 

additional information on the overall 

burdens and costs, as well as the 

relative burdens of each activity 

described here. Also, for a more 

comprehensive list of requirements 

imposed on 40 CFR part 70 sources 

(hence, burden on sources), see the 

requirements of 40 CFR 70.3, 40 CFR 

70.5, 40 CFR 70.6, and 40 CFR 70.7. The 

activities described above, which are 

quite extensive and time consuming, 

would be a significant burden on the 

non-major sources that would be subject 

to the proposed NSPS, in particular for 

well completion and/or pneumatic 

devices, considering the short duration 

of a well completion and the one time 

equipment installation of a pneumatic 

controller for meeting the proposed 

NSPS. Furthermore, some of the nonmajor sources that would be subject to 

the proposed NSPS may be small 

entities that may lack the technical 

resources and, therefore, need assistance 

from the permitting authorities to 

comply with the title V permitting 

requirements. Based on our projections, 

over 20,000 well completions (for both 

new hydraulically fractured gas wells 

and for existing gas wells that are 

subsequently fractured or re-fractured) 

will be performed each year. For 

pneumatic controller affected facilities, 

we estimate that approximately 14,000 

new controllers would be subject to the 

NSPS each year. Our estimated numbers 

of affected facilities that would be 

subject to the proposed NSPS for storage 

vessels and compressors are smaller 

(around 500 compressors and 300 

storage vessels). Although we do not 

know the total number of non-major 

sources that would be subject to the 

proposed NSPS, based on the estimated 

numbers of affected facilities, we 

anticipate a significant increase in the 

number of permit applications that 

permitting authorities would have to 

process each year. This significant 

burden on the permitting authorities 

raises a concern with the potential 

difficulty or delay that the small entities 

may face in obtaining sufficient 

assistance from the permitting 

authorities. 

The third factor we considered is 

whether the costs of title V permitting 

for these area sources would be 

justified, taking into consideration any 

potential gains in compliance likely to 

occur for such sources. We concluded, 

in considering the first factor, that the 

monitoring, recordkeeping and 

reporting requirements in this proposed 

NSPS assure compliance with the 

proposed standards, that title V would 

not result in significant improvement to 

these compliance requirements and, 

that, in some instances, certain title V 

compliance requirements may not be 

appropriate. In addition, as discussed 

above in our consideration of the second 

factor, we have concerns with the 

potential burdens that title V may 

impose on these sources. In addition, 

below in our consideration of the fourth 

factor, we find that there are adequate 

implementation and enforcement 

programs in place to assure compliance 

with the proposed NSPS. In light of the 

above, we find that the costs of title V 

permitting are not justified for the 

sources we propose to exempt. 

Accordingly, the third factor supports 

title V exemption for the oil and gas 

NSPS non-major sources. 

The fourth factor we considered is 

whether there are implementation and 

enforcement programs in place that are 

sufficient to assure compliance with the 

proposed NSPS for oil and gas sources 

without relying on title V permits. The 

CAA provides States the opportunity to 

take delegation of NSPS. Before the EPA 

will delegate the program, the EPA will 

evaluate the state programs to ensure 

that states have adequate capability to 

enforce the CAA section 111 regulations 

and provide assurances that they will 

enforce the NSPS. In addition, EPA 

retains authority to enforce this NSPS 

anytime under CAA sections 111, 113 

and 114. Accordingly, we can enforce 

the monitoring, recordkeeping and 

reporting requirements, which, as 

discussed under the first factor, are 

adequate to assure compliance with this 

NSPS. Also, states and the EPA often 

conduct voluntary compliance 

assistance, outreach and education 

programs (compliance assistance 

programs), which are not required by 

statute. We determined that these 

additional programs will supplement 

and enhance the success of compliance 

with these proposed standards. We 

believe that the statutory requirements 

for implementation and enforcement of 

this NSPS by the delegated states, the 

EPA and the additional assistance 

programs described above together are 

sufficient to assure compliance with 

these proposed standards without 

relying on title V permitting. 

Our balance of the four factors 

strongly supports a finding that title V 

is unnecessarily burdensome for the oil 

and gas non-major sources. While title 

V might add additional compliance 

requirements if imposed, we believe 

that there would not be significant 

improvements to the compliance 

requirements in this proposed rule 

because the proposed rule requirements 

are specifically designed to assure 

compliance with the proposed NSPS 

and, as explained above, some of the 

title V requirements may not be 

appropriate for certain operations and/ 

or proposed standards. We are also 

concerned with the potential burden 

that title V may impose on some of these 


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sources. In light of little or no potential 

gain in compliance if title V were 

required, we do not believe that the 

costs of title V permitting is justified in 

this case. Finally, there are adequate 

implementation and enforcement 

programs in place to assure compliance 

with these proposed standards. Thus, 

we propose that title V permitting is 

‘‘unnecessarily burdensome’’ for the oil 

and gas non-major sources. 

In addition to evaluating whether 

compliance with title V requirements is 

‘‘unnecessarily burdensome,’’ EPA also 

considered, consistent with guidance 

provided by the legislative history of 

section 502(a), whether exempting oil 

and gas NSPS non-major sources from 

title V requirements would adversely 

affect public health, welfare or the 

environment. The title V permit 

program does not impose new 

substantive air quality control 

requirements on sources, but instead 

requires that certain procedural 

measures be followed, particularly with 

respect to determining compliance with 

applicable requirements. As stated in 

our consideration of factor one, title V 

would not lead to significant 

improvements in the compliance 

requirements for the proposed NSPS. 

For the reason stated above, we believe 

that exempting these non-major sources 

from title V permitting requirements 

would not adversely affect public 

health, welfare or the environment. 

On the contrary, we are concerned 

that requiring title V in this case could 

potentially adversely affect public 

health, welfare or the environment. As 

mentioned above, we anticipate a 

significant increase in the number of 

permit applications that permitting 

authorities would have to process each 

year. Depending on the number of nonmajor sources that would be subject to 

this rule, requiring permits for those 

sources, at least in the first few years of 

implementation, could potentially 

adversely affect public health, welfare 

or the environment by shifting state 

agencies resources away from assuring 

compliance for major sources (which 

cannot be exempt from title V) to 

issuing new permits for these non-major 

sources, potentially reducing overall air 

program effectiveness. 

Based on the above analysis, we 

conclude that title V permitting would 

be ‘‘unnecessarily burdensome’’ for oil 

and gas NSPS non-major sources. We 

are, therefore, proposing that these nonmajor sources be exempt from title V 

permitting requirements. 

VI. Rationale for Proposed Action for 

NSPS 

A. What did we evaluate relative to 

NSPS? 

As noted above, there are two existing 

NSPS that address emissions from the 

Oil and Natural Gas source category. 

These NSPS are relatively narrow in 

scope, as they address emissions only at 

natural gas processing plants. 

Specifically, 40 CFR part 60, subpart 

KKK addresses VOC emissions from 

leaking equipment at onshore natural 

gas processing plants and 40 CFR part 

60, subpart LLL addresses SO2

emissions from natural gas processing 

plants. 

CAA section 111(b)(1)(B) requires the 

EPA to review and revise, if appropriate, 

NSPS standards. Accordingly, we 

evaluated whether the existing NSPS 

reflect the BSER for the emission 

sources that they address. This review 

was conducted by examining currently 

used, new and emerging control systems 

and assessing whether they represent 

advances in emission reduction 

techniques from those upon which the 

existing NSPS are based, including 

advances in LDAR approaches and SO2

control at natural gas processing plants. 

For each new or emerging control 

option identified, we then evaluated 

emission reductions, costs, energy 

requirements and non-air quality 

impacts, such as solid waste generation. 

In this package, we have also 

evaluated whether there were additional 

pollutants emitted by facilities in the 

Oil and Natural Gas source category that 

warrant regulation and for which we 

have adequate information to 

promulgate standards of performance. 

Finally, we have identified additional 

processes in the Oil and Natural Gas 

source category for which it may be 

appropriate to develop performance 

standards. This would include 

processes that emit the currently 

regulated pollutants, VOC and SO2, as 

well as any additional pollutants for 

which we determined regulation to be 

appropriate. 

B. What are the results of our 

evaluations and proposed actions 

relative to NSPS? 

1. Do the existing NSPS reflect the BSER 

for sources covered? 

Consistent with our obligations under 

CAA section 111(b), we evaluated 

whether the control options reflected in 

the current NSPS for the Oil and Natural 

Gas source category still represent 

BSER. To evaluate the BSER options for 

equipment leaks, we reviewed EPA’s 

current LDAR programs, the Reasonably 

Available Control Technology (RACT)/ 

Best Available Control Technology 

(BACT)/Lowest Achievable Emission 

Rate (LAER) Clearinghouse (RBLC) 

database, and emerging technologies 

that have been identified by partners in 

the Natural Gas STAR program. 

The current NSPS for equipment leaks 

of VOC at natural gas processing plants 

(40 CFR part 60, subpart KKK) requires 

compliance with specific provisions of 

40 CFR part 60, subpart VV, which is a 

LDAR program, based on the use of EPA 

Method 21 to identify equipment leaks. 

In addition to the subpart VV 

requirements, we reviewed the LDAR 

requirements in 40 CFR part 60, subpart 

VVa. This LDAR program is considered 

to be more stringent than the subpart VV 

requirements, because it has lower 

component leak threshold definitions 

and more frequent monitoring, in 

comparison to the subpart VV program. 

Furthermore, subpart VVa requires 

monitoring of connectors, while subpart 

VV does not. We also reviewed options 

based on optical gas imaging. 

As mentioned above, the currently 

required LDAR program for natural gas 

processing plants (40 CFR part 60, 

subpart KKK) is based on EPA Method 

21, which requires the use of an organic 

vapor analyzer to monitor components 

and to measure the concentration of the 

emissions in identifying leaks. We 

recognize that there have been 

advancements in the use of optical gas 

imaging to detect leaks from these same 

types of components. These instruments 

do not yet provide a direct measure of 

leak concentrations. The instruments 

instead provide a measure of a leak 

relative to an instrument specific 

calibration point. Since the 

promulgation of 40 CFR part 60, subpart 

KKK (which requires Method 21 leak 

measurement monthly), the EPA has 

updated the 40 CFR part 60 General 

Provisions to allow the use of advanced 

leak detection tools, such as optical gas 

imaging and ultrasound equipment as 

an alternative to the LDAR protocol 

based on Method 21 leak measurements 

(see 40 CFR 60.18(g)). The alternative 

work practice allowing use of these 

advanced technologies includes a 

provision for conducting a Method 21- 

based LDAR check of the regulated 

equipment annually to verify good 

performance. 

In our review, we evaluated 4 options 

in considering BSER for VOC equipment 

leaks at natural gas processing plants. 

One option we evaluated consists of 

changing from a 40 CFR part 60, subpart 

VV-level program, which is what 40 

CFR part 60, subpart KKK currently 

requires, to a 40 CFR part 60, subpart 

VVa program, which applies to new 


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10Because optical gas imaging is used to view 

several pieces of equipment at a facility at once to 

survey for leaks, options involving imaging are not 

amenable to a component by component analysis. 

synthetic organic chemical plants after 

2006. Subpart VVa lowers the leak 

definition for valves from 10,000 parts 

per million (ppm) to 500 ppm, and 

requires the monitoring of connectors. 

In our analysis of these impacts, we 

estimated that, for a typical natural gas 

processing plant, the incremental cost 

effectiveness of changing from the 

current subpart VV-level program to a 

subpart VVa-level program using 

Method 21 is $3,352 per ton of VOC 

reduction. 

In evaluating 40 CFR part 60, subpart 

VVa-level LDAR at processing plants, 

we also analyzed separately the 

individual types of components (valves, 

connectors, pressure relief devices and 

open-ended lines) to determine cost 

effectiveness for individual 

components. Detailed discussions of 

these component-by-component 

analyses are included in the TSD in the 

docket. Cost effectiveness ranged from 

$144 per ton of VOC (for valves) to 

$4,360 per ton of VOC (for connectors), 

with no change in requirements for 

pressure relief devices and open-ended 

lines. 

Another option we evaluated for gas 

processing plants was the use of optical 

gas imaging combined with an annual 

EPA Method 21 check (i.e., the 

alternative work practice for monitoring 

equipment for leaks at 40 CFR 60.18(g)). 

We had previously determined that the 

VOC reduction achieved by this 

combination of optical gas imaging and 

Method 21 would be equivalent to 

reductions achieved by the 40 CFR part 

60, subpart VVa-level program. Based 

on that emission reduction level, we 

determined the cost effectiveness of this 

option to be $6,462 per ton of VOC 

reduction. This analysis is based on the 

facility purchasing an optical gas 

imaging system costing $85,000. 

However, we identified at least one 

manufacturer who rents the optical gas 

imaging systems. That manufacturer 

rents the optical gas imaging system for 

$3,950 per week. Using this rental cost 

in place of the purchase cost, the VOC 

cost effectiveness of the monthly optical 

gas imaging combined with annual 

Method 21 checks is $4,638 per ton of 

VOC reduction.10 A third option we 

evaluated consisted of monthly optical 

gas imaging without an annual Method 

21 check. We estimated the annual cost 

of the monthly optical gas imaging 

LDAR program to be $76,581, based on 

camera purchase, or $51,999, based on 

camera rental. However, because we 

were unable to estimate the VOC 

emissions achieved by an optical 

imaging program alone, we were unable 

to estimate the cost effectiveness of this 

option. 

Finally, we evaluated a fourth option 

similar to the third option, except that 

the optical gas imaging would be 

performed annually rather than 

monthly. For this option, we estimated 

the annual cost to be $43,851, based on 

camera purchase, or $18,479, based on 

camera rental. 

We request comment on the 

applicability of an LDAR program based 

solely on the use of optical gas imaging. 

Of most use to us would be information 

on the effectiveness of this and, 

potentially, other advanced 

measurement technologies, to detect 

and repair small leaks on the same order 

or smaller than specified in the 40 CFR 

part 60, subpart VVa equipment leak 

requirements and the effects of 

increased frequency of and associated 

leak detection, recording and repair 

practices. 

Because we could not estimate the 

cost effectiveness of options 3 and 4, we 

could not identify either of these two 

options as BSER for reducing VOC leaks 

at gas processing plants. Because 

options 1 and 2 have achieved 

equivalent VOC reduction and are both 

cost effective, we believe that both 

options 1 and 2 reflect BSER for LDAR 

for natural gas processing plants. As 

mentioned above, option 1 is the LDAR 

in 40 CFR part 60, subpart VVa and 

option 2 is the alternative work practice 

at 40 CFR 60.18(g) and is already 

available to use as an alternative to 

subpart VVa LDAR. Therefore, we 

propose that the NSPS for equipment 

leaks of VOC at gas processing plants be 

revised to require compliance with the 

subpart VVa equipment leak 

requirements. 

For 40 CFR part 60, subpart LLL, we 

reviewed control systems for SO2

emissions from sweetening units located 

at natural gas processing plants, 

including those followed by a sulfur 

recovery unit. Subpart LLL provides 

specific standards for SO2 emission 

reduction efficiency, on the basis of 

sulfur feed rate and the sulfur content 

of the natural gas. 

According to available literature, the 

most widely used process for converting 

H2S in acid gases (i.e., H2S and CO2) 

separated from natural gas by a 

sweetening process (such as amine 

treating) into elemental sulfur is the 

Claus process. Sulfur recovery 

efficiencies are higher with higher 

concentrations of H2S in the feed stream 

due to the thermodynamic equilibrium 

limitation of the Claus process. The 

Claus sulfur recovery unit produces 

elemental sulfur from H2S in a series of 

catalytic stages, recovering up to 97- 

percent recovery of the sulfur from the 

acid gas from the sweetening process. 

Further, sulfur recovery is accomplished 

by making process modifications or by 

employing a tail gas treatment process 

to convert the unconverted sulfur 

compounds from the Claus unit. 

We evaluated process modifications 

and tail gas treatment options when we 

proposed 40 CFR part 60, subpart LLL. 

49 FR 2656, 2659–2660 (1984). As we 

explained in the preamble to the 

proposed subpart LLL, control through 

sulfur recovery with tail gas treatment 

may not always be cost effective, 

depending on sulfur feed rate and inlet 

H2S concentrations. Therefore, other 

methods of increasing sulfur recovery 

via process modifications were 

evaluated. As shown in the original 

evaluation, the performance capabilities 

and costs of each of these technologies 

are highly dependent on the ratio of H2S 

and CO2 in the gas stream and the total 

quantity of sulfur in the gas stream 

being treated. The most effective means 

of control was selected as BSER for the 

different stream characteristics. As a 

result, separate emissions limitations 

were developed in the form of equations 

that calculate the required initial and 

continuous emission reduction 

efficiency for each plant. The equations 

were based on the design performance 

capabilities of the technologies selected 

as BSER relative to the gas stream 

characteristics. 49 FR 2656, 2663–2664 

(1984). The emission limit for sulfur 

feed rates at or below 5 long tons per 

day, regardless of H2S content, was 79 

percent. For facilities with sulfur feed 

rates above 5 long tons per day, the 

emission limits ranged from 79 percent 

at an H2S content below 10 percent to 

99.8 percent for H2S contents at or 

above 50 percent. 

To review these emission limitations, 

we performed a search of the RBLC 

database and state regulations. No state 

regulations identified had emission 

limitations more stringent than 40 CFR 

part 60, subpart LLL. However, the 

RBLC database search identified two 

entries with SO2 emission reductions of 

99.9 percent. One entry is for a facility 

in Bakersfield, California, with a 90 long 

ton per day sulfur recovery unit 

followed by an amine-based tail-gas 

treating unit. The second entry is for a 

facility in Coden, Alabama, with a 

sulfur recovery unit with a sulfur feed 

rate of 280 long tons per day, followed 

by selective catalytic reduction and a 

tail gas incinerator. However, neither of 

these entries contained information 

regarding the H2S contents of the feed 


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52756 Federal Register / Vol. 76, No. 163 / Tuesday, August 23, 2011 / Proposed Rules 

11U.S. EPA. Inventory of U.S. Greenhouse Gas 

Inventory and Sinks. 1990–2009. http:// 

www.epa.gov/climatechange/emissions/ 

downloads10/US-GHG-Inventory2010_ExecutiveSummary.pdf. 

stream. Because the sulfur recovery 

efficiency of these large sized plants was 

greater than 99.8 percent, we 

reevaluated the original data. Based on 

the available cost information, it 

appears that a 99.9-percent efficiency is 

cost effective for facilities with a sulfur 

feed rate greater than 5 long tons per 

day and H2S content equal to or greater 

than 50 percent. Based on our review, 

we are proposing that the maximum 

initial and continuous efficiency for 

facilities with a sulfur feed rate greater 

than 5 long tons per day and an H2S 

content equal to or greater than 50 

percent be raised to 99.9 percent. We are 

not proposing to make changes to the 

equations. 

Our search of the RBLC database did 

not uncover information regarding costs 

and achievable emission reductions to 

suggest that the emission limitations for 

facilities with a sulfur feed rate less than 

5 long tons per day or H2S content less 

than 50 percent should be modified. 

Therefore, we are not proposing any 

changes to the emissions limitations for 

facilities with sulfur feed rate and H2S 

content less than 5 long tons per day 

and 50 percent, respectively. 

2. What pollutants are being evaluated 

in this Oil and Natural Gas NSPS 

package? 

The two current NSPS for the Oil and 

Natural Gas source category address 

emissions of VOC and SO2. In addition 

to these pollutants, sources in this 

source category also emit a variety of 

other pollutants, most notably, air 

toxics. As discussed elsewhere in this 

notice, there are NESHAP that address 

air toxics from the oil and natural gas 

sector. 

In addition, processes in the Oil and 

Natural Gas source category emit 

significant amounts of methane. The 

1990–2009 U.S. GHG Inventory 

estimates 2009 methane emissions from 

Petroleum and Natural Gas Systems (not 

including petroleum refineries) to be 

251.55 MMtCO2e (million metric tons of 

CO2-equivalents (CO2e)).11 The 

emissions estimated from well 

completions and recompletions exclude 

a significant number of wells completed 

in tight sand plays, such as the 

Marcellus, due to availability of data 

when the 2009 Inventory was 

developed. The estimate in this 

proposal includes an adjustment for 

tight sand plays (being considered as a 

planned improvement in development 

of the 2010 Inventory). This adjustment 

would increase the 2009 Inventory 

estimate by 76.74 MMtCO2e. The total 

methane emissions from Petroleum and 

Natural Gas Systems, based on the 2009 

Inventory, adjusted for tight sand plays 

and the Marcellus, is 328.29 MMtCO2e. 

Although this proposed rule does not 

include standards for regulating the 

GHG emissions discussed above, we 

continue to assess these significant 

emissions and evaluate appropriate 

actions for addressing these concerns. 

Because many of the proposed 

requirements for control of VOC 

emissions also control methane 

emissions as a co-benefit, the proposed 

VOC standards would also achieve 

significant reduction of methane 

emissions. 

Significant emissions of oxides of 

nitrogen (NOX) also occur at oil and 

natural gas sites due to the combustion 

of natural gas in reciprocating engines 

and combustion turbines used to drive 

the compressors that move natural gas 

through the system, and from 

combustion of natural gas in heaters and 

boilers. While these engines, turbines, 

heaters and boilers are co-located with 

processes in the oil and natural gas 

sector, they are not in the Oil and 

Natural Gas source category and are not 

being addressed in this action. The NOX

emissions from engines and turbines are 

covered by the Standards of 

Performance for Stationary Spark 

Internal Combustion Engines (40 CFR 

part 60, subpart JJJJ) and Standards of 

Performance for Stationary Combustion 

Turbines (40 CFR part 60, subpart 

KKKK), respectively. 

An additional source of NOX

emissions would be pit flaring of VOC 

emissions from well completions during 

periods where REC is not feasible, as 

would be required under our proposed 

operational standards for wellhead 

affected facilities. As discussed below in 

section VI.B.4 (well completion), pit 

flaring is the only way we identified of 

controlling VOC emissions during these 

periods. Because there is no way of 

directly measuring the NOX produced, 

nor is there any way of applying 

controls other than minimizing flaring, 

we propose to allow flaring only when 

REC is not feasible. We have included 

our estimates of NOX formation from pit 

flaring in our discussion of secondary 

impacts in section VI.B.4. 

3. What emission sources are being 

evaluated in this Oil and Natural Gas 

NSPS package? 

The current NSPS only cover 

emissions of VOC and SO2 from one 

type of facility in the oil and natural gas 

sector, which is the natural gas 

processing plant. This is the only type 

of facility in the Oil and Natural Gas 

source category where we would expect 

SO2 to be emitted directly, although H2S 

contained in sour gas, when oxidized in 

the atmosphere or combusted in boilers 

and heaters in the field, forms SO2 as a 

product of oxidation. These field boilers 

and heaters are not part of the Oil and 

Natural Gas source category and are 

generally too small to be regulated by 

the NSPS covering boilers (i.e., they 

have a heat input of less than 10 million 

British Thermal Units per hour). 

However, we may consider addressing 

them as part of a future sector-based 

strategy for the oil and natural gas 

sector. 

In addition to VOC emissions from 

gas processing plants, there are 

numerous sources of VOC throughout 

the oil and natural gas sector that are 

not addressed by the current NSPS. As 

explained above in section V.A, 

pursuant to CAA section 111(b), to the 

extent necessary, we are modifying the 

listed category to include all segments 

of the oil and natural gas industry for 

regulation. We are also proposing VOC 

standards to cover additional processes 

at oil and natural gas operations. These 

include NSPS for VOC from gas well 

completions, pneumatic controllers, 

compressors and storage vessels. 

We believe that produced water 

ponds are also a potentially significant 

source of emissions, but we have only 

limited information. We, therefore, 

solicit comments on produced water 

ponds, particularly in the following 

subject areas: 

(a) We are requesting comments 

pertaining to methods for calculating 

emissions. The State of Colorado 

currently uses a mass balance that 

assumes 100 percent of the VOC content 

is emitted to the atmosphere. Water9, an 

air emissions model, is another option 

that has some limitations, including 

poor methanol estimation. 

(b) We are requesting additional 

information on typical VOC content in 

produced water and any available 

chemical analyses, including data that 

could help clarify seasonal variations or 

differences among gas fields. 

Additionally, we request data that 

increase our understanding of how 

changing process variables or age of 

wells affect produced water output and 

VOC content. 

(c) We solicit information on the size 

and throughput capacity of typical 

evaporation pond facilities and request 

suggestions on parameters that could be 

used to define affected facilities or 

affected sources. We also seek 

information on impacts of smaller 

evaporation pits that are co-located with 

drilling operations, whether those 


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warrant control and, if so, how controls 

should be developed. 

(d) An important factor is cost of 

emission reduction technologies, 

including recovery credits or cost 

savings realized from recovered salable 

product. We are seeking information on 

these considerations as well. 

(e) We are also seeking information on 

any limitations for emission reduction 

technologies such as availability of 

electricity, waste generation and 

disposal and throughput and 

concentration constraints. 

(f) Finally, we solicit information on 

separator technologies that are able to 

improve the oil-water separation 

efficiency. 

4. What are the rationales for the 

proposed NSPS? 

We have provided below our 

rationales for the proposed BSER 

determinations and performance 

standards for a number of VOC emission 

sources in the Oil and Natural Gas 

source category that are not covered by 

the existing NSPS. Our general process 

for evaluating systems of emission 

reduction for the emission sources 

discussed below included: (1) 

Identification of available control 

measures; (2) evaluation of these 

measures to determine emission 

reductions achieved, associated costs, 

nonair environmental impacts, energy 

impacts and any limitations to their 

application; and (3) selection of the 

control techniques that represent BSER 

based on the information we 

considered. 

We identified the control options 

discussed in this package through our 

review of relevant state and local 

requirements and mitigation measures 

developed and reported by the EPA’s 

Natural Gas STAR program. The EPA’s 

Natural Gas STAR program has worked 

with industry partners since 1993 to 

identify cost effective measures to 

reduce emissions of methane and other 

pollutants from natural gas operations. 

We relied heavily on this wealth of 

information in conducting this review. 

We also identified state regulations, 

primarily in Colorado and Wyoming, 

which require mitigation measures for 

some emission sources in the Oil and 

Natural Gas source category. 

a. NSPS for Well Completions 

Well completion activities are a 

significant source of VOC emissions, 

which occur when natural gas and nonmethane hydrocarbons are vented to the 

atmosphere during flowback of a 

hydraulically fractured gas well. 

Flowback emissions are short-term in 

nature and occur over a period of 

several days following fracturing of a 

new well or refracturing of an existing 

well. Well completions include multiple 

steps after the well bore hole has 

reached the target depth. These steps 

include inserting and cementing-in well 

casing, perforating the casing at one or 

more producing horizons, and often 

hydraulically fracturing one or more 

zones in the reservoir to stimulate 

production. Well recompletions may 

also include hydraulic fracturing. 

Hydraulic fracturing is one technique 

for improving gas production where the 

reservoir rock is fractured with very 

high pressure fluid, typically water 

emulsion with a proppant (generally 

sand) that ‘‘props open’’ the fractures 

after fluid pressure is reduced. 

Emissions are a result of the backflow of 

the fracture fluids and reservoir gas at 

high volume and velocity necessary to 

lift excess proppant and fluids to the 

surface. This multi-phase mixture is 

often directed to a surface 

impoundment where natural gas and 

VOC vapors escape to the atmosphere 

during the collection of water, sand and 

hydrocarbon liquids. As the fracture 

fluids are depleted, the backflow 

eventually contains more volume of 

natural gas from the formation. Wells 

that are fractured generally have great 

amounts of emissions because of the 

extended length of the flowback period 

required to purge the well of the fluids 

and sand that are associated with the 

fracturing operation. Along with the 

fluids and sand from the fracturing 

operation, the 3- to 10-day flowback 

period also results in emissions of 

natural gas and VOC that would not 

occur in large quantities at oil wells or 

at natural gas wells that are not 

fractured. Thus, we estimate that gas 

well completions involving hydraulic 

fracturing vent substantially more VOC, 

approximately 200 times more, than 

completions not involving hydraulic 

fracturing. Specifically, we estimate that 

uncontrolled well completion emissions 

for a hydraulically fractured gas well are 

approximately 23 tons of VOC, where 

emissions for a conventional gas well 

completion are around 0.12 tons VOC. 

These estimates are explained in detail 

in the TSD available in the docket. 

Based on our review, we believe that 

emissions from recompletions of 

previously completed wells that are 

fractured or refractured to stimulate 

production or to begin production from 

a new production horizon are of similar 

magnitude and composition as 

emissions from completions of new 

wells that have been hydraulically 

fractured. 

EPA has based the NSPS impacts 

analysis on best available emission data. 

However, we recognize that there is 

uncertainty associated with our 

estimates. For both new completions 

and recompletions, there are a variety of 

factors that will determine the length of 

the flowback period and actual volume 

of emissions such as the number of 

zones, depth, pressure of the reservoir, 

gas composition, etc. This variability 

means there will be some wells which 

emit more than the estimated emission 

factor and some wells that emit less. 

During our review, we examined 

information from the Natural Gas STAR 

program and the Colorado and 

Wyoming state rules covering well 

completions. We identified two 

subcategories of fractured gas wells: (1) 

Non-exploratory and non-delineation 

wells; and (2) exploratory and 

delineation wells. An exploratory well 

is the first well drilled to determine the 

presence of a producing reservoir and 

the well’s commercial viability. A 

delineation well is a well drilled to 

determine the boundary of a field or 

producing reservoir. Because 

exploratory and delineation wells are 

generally isolated from existing 

producing wells, there are no gathering 

lines available for collection of gas 

recovered during completion 

operations. In contrast, non-exploratory 

and non-delineation wells are located 

where existing, producing wells are 

connected to gathering lines and are, 

therefore, able to be connected to a 

gathering line to collect recovered 

salable natural gas product that would 

otherwise be vented to the atmosphere 

or combusted. 

For subcategory 1, we identified 

‘‘green’’ completion, which we refer to 

as REC, as an option for reducing VOC 

emissions during well completions. REC 

are performed by separating the 

flowback water, sand, hydrocarbon 

condensate and natural gas to reduce 

the portion of natural gas and VOC 

vented to the atmosphere, while 

maximizing recovery of salable natural 

gas and VOC condensate. In some cases, 

for a portion of the completion 

operation, such as when CO2 or nitrogen 

is injected with the fracture water, 

initial gas produced is not of suitable 

quality to introduce into the gathering 

line due to CO2 or nitrogen content or 

other undesirable characteristic. In such 

cases, for a portion of the flowback 

period, gas cannot be recovered, but 

must be either vented or combusted. In 

practice, REC are often combined with 

combustion to minimize the amount of 

gas and condensate being vented. This 

combustion process is rather crude, 

consisting of a horizontal pipe 


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downstream of the REC equipment, 

fitted with a continuous ignition source 

and discharging over a pit near the 

wellhead. Because of the nature of the 

flowback (i.e., with periods of water, 

condensate, and gas in slug flow), 

conveying the entire portion of this 

stream to a traditional flare control 

device or other control device, such as 

a vapor recovery unit, is not feasible. 

These control devices are not designed 

to accommodate the multiphase flow 

consisting of water, sand and 

hydrocarbon liquids, along with the gas 

and vapor being controlled. Although 

‘‘pit flaring’’ does not employ a 

traditional flare control device, and is 

not capable of being tested or monitored 

for efficiency due to the multiphase slug 

flow and intermittent nature of the 

discharge of gas, water and sand over 

the pit, it does provide a means of 

minimizing vented gas and is preferable 

to venting. Because of the rather large 

exposed flame, open pit flaring can 

present a fire hazard or other 

undesirable impacts in some situations 

(e.g., dry, windy conditions, proximity 

to residences, etc.). As a result, we are 

aware that owners and operators may 

not be able to pit flare unrecoverable gas 

safely in every case. In some cases, pit 

flaring may be prohibited by local 

ordinance. 

Equipment required to conduct REC 

may include tankage, special gas-liquidsand separator traps and gas 

dehydration. Equipment costs 

associated with REC will vary from well 

to well. Typical well completions last 

between 3 and 10 days and costs of 

performing REC are projected to be 

between $700 and $6,500 per day, 

including a cost of approximately 

$3,523 per completion event for the pit 

flaring equipment. However, there are 

savings associated with the use of REC 

because the gas recovered can be 

incorporated into the production stream 

and sold. In fact, we estimate that REC 

will result in an overall net cost savings 

in many cases. 

The emission reductions for a 

hydraulically fractured well are 

estimated to be around 22 tons of VOC. 

Based on an average incremental cost of 

$33,237 per completion, the cost 

effectiveness of REC, without 

considering any cost savings, is around 

$1,516 per ton of VOC (which we have 

previously found to be cost effective on 

average). When the value of the gas 

recovered (approximately 150 tons of 

methane per completion) is considered, 

the cost effectiveness is estimated as an 

average net savings of $99 per ton VOC 

reduced, using standard discount rates. 

We believe that these costs are very 

reasonable, given the emission 

reduction that would be achieved. Aside 

from the potential hazards associated 

with pit flaring, in some cases, we did 

not identify any nonair environmental 

impacts, health or energy impacts 

associated with REC combined with 

combustion. However, pit flaring would 

produce NOX emissions. Because we 

believe that these emissions cannot be 

controlled or measured directly due to 

the open combustion process 

characteristic of pit flaring, we used 

published emission factors (EPA 

Emission Guidelines AP–42) to estimate 

the NOX emissions for purposes of 

assessing secondary impacts. For 

category 1 well completions, we 

estimated that 0.02 tons of NOX are 

produced per event. This is based on the 

assumption that 5 percent of the 

flowback gas is combusted by the 

combustion device. The 1.2 tons of VOC 

controlled during the pit flaring portion 

of category 1 well completions is 

approximately 57 times greater than the 

NOX produced by pit flaring. Thus, we 

believe that the benefit of the VOC 

reduction far outweighs the secondary 

impact of NOX formation during pit 

flaring. 

We believe that, based on the analysis 

above, REC in combination with 

combustion is BSER for subcategory 1 

wells. We considered setting a 

numerical performance standard for 

subcategory 1 wells. However, it is not 

practicable to measure the emissions 

during pit flaring or venting because the 

gas is discharged over the pit along with 

water and sand in multiphase slug flow. 

Therefore, we believe it is not feasible 

to set a numerical performance 

standard. Pursuant to section 111(h)(2) 

of the CAA, we are proposing an 

operational standard for subcategory 1 

wells that would require a combination 

of REC and pit flaring to minimize 

venting of gas and condensate vapors to 

the atmosphere, with provisions for 

venting in lieu of pit flaring for 

situations in which pit flaring would 

present safety hazards or for periods 

when the flowback gas is 

noncombustible due to high 

concentrations of nitrogen or CO2. The 

proposed operational standard would be 

accompanied by requirements for 

documentation of the overall duration of 

the completion event, duration of 

recovery using REC, duration of 

combustion, duration of venting, and 

specific reasons for venting in lieu of 

combustion. 

We recognize that there is 

heterogeneity in well operations and 

costs, and that while RECs may be costeffective on average, they may not be for 

all operators. Nonetheless, EPA is 

proposing to require an operational 

standard rather than a performancebased standard (e.g., requiring that some 

percentage of emissions be flared or 

captured), because we believe there are 

no feasible ways for operators to 

measure emissions with enough 

certainty to demonstrate compliance 

with a performance-based standard for 

REC in combination with pit flaring. 

The EPA requests comment on this and 

seeks input on whether alternative 

approaches to requiring REC for all 

operators with access to pipelines may 

exist that would allow operators to meet 

a performance-based standard if they 

can demonstrate that an REC is not cost 

effective. 

We have discussed above certain 

situations where unrecoverable gas 

would be vented because pit flaring 

would present a fire hazard or is 

infeasible because gas is 

noncombustible due to high 

concentrations of nitrogen or CO2. We 

solicit comment on whether there are 

other such situations where flaring 

would be unsafe or infeasible, and 

potential criteria that would support 

venting in lieu of pit flaring. In addition, 

we learned that coalbed methane 

reservoirs may have low pressure, 

which would present a technical barrier 

for performing a REC because the well 

pressure may not be substantial enough 

to overcome gathering line pressure. In 

addition, we identified that coalbed 

methane wells often have low to almost 

no VOC emissions, even following the 

hydraulic fracturing process. We solicit 

comment on criteria and thresholds that 

could be used to exempt some well 

completion operations occurring in 

coalbed methane reservoirs from the 

requirements for subcategory 1 wells. 

Of the 25,000 new and modified 

fractured gas wells completed each year, 

we estimate that approximately 3,000 to 

4,000 currently employ reduced 

emission completion. We expect this 

number to increase to over 21,000 REC 

annually as operators comply with the 

proposed NSPS. We estimate that 

approximately 9,300 new wells and 

12,000 existing wells will be fractured 

or refractured annually that would be 

subject to subcategory 1 requirements 

under the NSPS. We believe that there 

will be a sufficient supply of REC 

equipment available by the time the 

NSPS becomes effective. However, 

energy availability could be affected if a 

shortage of REC equipment was allowed 

to cause delays in well completions. We 

request comment on whether sufficient 

supply of this equipment and personnel 

to operate it will be available to 

accommodate the increased number of 

REC by the effective date of the NSPS. 

We also request specific estimates of 


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Federal Register / Vol. 76, No. 163 / Tuesday, August 23, 2011 / Proposed Rules 52759 

how much time would be required to 

get enough equipment in operation to 

accommodate the full number of REC 

performed annually. 

In the event that public comments 

indicate that available equipment would 

likely be insufficient to accommodate 

the increase in number of REC 

performed, we are considering phasing 

in requirements for well completions 

that would achieve an overall 

comparable level of environmental 

benefit. For example, operators 

performing completions of fractured or 

refractured existing wells (i.e., modified 

wells) could be allowed to control 

emissions through pit flaring instead of 

REC for some period of time. After some 

date certain, all modified wells would 

be subject to REC. We solicit comment 

on the phasing of requirements for REC 

along with suggestions for other ways to 

address a potential short-term REC 

equipment shortage that may hinder 

operators’ compliance with the 

proposed NSPS, while also achieving a 

comparable level of reduced emissions 

to the air. 

Although we have determined that, 

on average, reduced emission 

completions are cost effective, well and 

reservoir characteristics could vary, 

such that some REC are more cost 

effective than others. Unlike most 

stationary source controls, REC 

equipment is used only for a 3 to 10 day 

period. Our review found that most 

operators contract with service 

companies to perform REC rather than 

purchase the equipment themselves, 

which was reflected in our economic 

analysis. It is also possible that the 

contracting costs of supplying and 

operating REC equipment may rise in 

the short term with the increased 

demand for those services. We request 

comment and any available technical 

information to judge whether our 

assumption of $33,237 per well 

completion for this service given the 

projected number of wells in 2015 

subject to this requirement is accurate. 

We believe that the proposed rule 

regulates only significant emission 

sources for which controls are costeffective. Nevertheless, we solicit 

comment and supporting data on 

appropriate thresholds (e.g., pressure, 

flowrate) that we should consider in 

specifying which well completions are 

subject to the REC requirements for 

subcategory 1 wells. Comments 

specifying thresholds should include an 

analysis of why sources below these 

thresholds are not cost effective to 

control. 

In addition, there may be economic, 

technical or other opportunities or 

barriers associated with performing cost 

effective REC that we have not 

identified in our review. For example, 

some small regulated entities may have 

an increased source of revenue due to 

the captured product. On the other 

hand, some small regulated entities may 

have less access to REC than larger 

regulated entities might have. We 

request information on such 

opportunities and barriers that we 

should consider and suggestions for 

how we may take them into account in 

structuring the NSPS. 

The second subcategory of fractured 

gas wells includes exploratory wells or 

delineation wells. Because these types 

of wells generally are not in proximity 

to existing gathering lines, REC is not an 

option, since there is no infrastructure 

in place to get the recovered gas to 

market or further processing. For these 

wells, the only potential control option 

we were able to identify is pit flaring, 

described above. As explained above, 

because of the slug flow nature of the 

flowback gas, water and sand, control by 

a traditional flare control device or other 

control devices, such as vapor recovery 

units, is infeasible, which leaves pit 

flaring as the only practicable control 

system for subcategory 2 wells. As also 

discussed above, open pit flaring can 

present a fire hazard or other 

undesirable impacts in some situations. 

Aside from the potential hazards 

associated with pit flaring, in some 

cases, we did not identify any nonair 

environmental impacts, health or energy 

impacts associated with pit flaring. 

However, pit flaring would produce 

NOX emissions. As in the case of 

category 1 wells, we believe that these 

emissions cannot be controlled or 

measured directly due to the open 

combustion process characteristic of pit 

flaring. We again used published 

emission factors to estimate the NOX

emissions for purposes of assessing 

secondary impacts. For category 2 well 

completions, we estimated that 0.32 

tons of NOX are produced as secondary 

emissions per completion event. This is 

based on the assumption that 95 percent 

of flowback gas is combusted by the 

combustion device. The 22 tons of VOC 

reduced during the pit flaring used to 

control category 2 well completions is 

approximately 69 times greater than the 

NOX produced. Thus, we believe that 

the benefit of the VOC reduction far 

outweighs the secondary impact of NOX

formation during pit flaring. 

In light of the above, we propose to 

determine that BSER for subcategory 2 

wells would be pit flaring. As we 

explained above, it is not practicable to 

measure the emissions during pit flaring 

or venting because the gas is discharged 

during flowback mixed with water and 

sand in multiphase slug flow. It is, 

therefore, not feasible to set a numerical 

performance standard. 

Pursuant to CAA section 111(h)(2), we 

are proposing an operational standard 

for subcategory 2 wells that requires 

minimization of venting of gas and 

hydrocarbon vapors during the 

completion operation through the use of 

pit flaring, with provisions for venting 

in lieu of pit flaring for situations in 

which flaring would present safety 

hazards or for periods when the 

flowback gas is noncombustible due to 

high concentrations of nitrogen or 

carbon dioxide. 

Consistent with requirements for 

subcategory 1 wells, owners or operators 

of subcategory 2 wells would be 

required to document completions and 

provide justification for periods when 

gas was vented in lieu of combustion. 

We solicit comment on whether there 

are other such situations where flaring 

would be unsafe or infeasible and 

potential criteria that would support 

venting in lieu of pit flaring. 

For controlling completion emissions 

at oil wells and conventional (nonfractured) gas wells, we have identified 

and evaluated the following control 

options: REC in conjunction with pit 

flaring and pit flaring alone. Due to the 

low uncontrolled VOC emissions of 

approximately 0.007 ton per completion 

and, therefore, low potential emission 

reductions from these events, the cost 

per ton of reduction based on REC 

would be extremely high (over $700,000 

per ton of VOC reduced). We evaluated 

the use of pit flaring alone as a system 

for controlling emissions from oil wells 

and conventional gas wells and 

determined that the cost costeffectiveness would be approximately 

$520,000 per ton for oil wells and 

approximately $32,000 per ton for 

conventional gas wells. In light of the 

high cost per ton of VOC reduction, we 

do not consider either of these control 

options to be BSER for oil wells and 

conventional wells. 

We propose that fracturing (or 

refracturing) and completion of an 

existing well (i.e., a well existing prior 

to August 23, 2011) is considered a 

modification under CAA section 111(a), 

because physical change occurs to the 

existing well, which includes the 

wellbore, casing and tubing, resulting in 

an emissions increase during the 

completion operation. The physical 

change, in this case, would be caused by 

the reperforation of the casing and 

tubing, along with the refracturing of the 

wellbore. The increased VOC emissions 

would occur during the flowback period 

following the fracturing or refracturing 

operation. Therefore, the proposed 


emcdonald on DSK2BSOYB1PROD with PROPOSALS2
52760 Federal Register / Vol. 76, No. 163 / Tuesday, August 23, 2011 / Proposed Rules 

standards for category 1 and category 2 

wells would apply to completions at 

existing fractured or refractured wells. 

EPA seeks comment on the 10 percent 

per year rate of refracturing for natural 

gas wells assumed in the impacts 

analysis found in the TSD. EPA has 

received anecdotal information 

suggesting that refracturing could be 

occurring much less frequently, while 

others suggest that the percent of wells 

refractured in a given year could be 

greater. We seek comment and 

comprehensive data and information on 

the rate of refracturing and key factors 

that influence or determine refracturing 

frequency. 

In addition to well completions, we 

considered VOC emissions occurring at 

the wellhead affected facility during 

subsequent day-to-day operations 

during well production. As discussed 

below in section VI.B.1.e, VOC 

emissions from wellheads are very small 

during production and account for 

about 2.6 tons VOC per year. We are not 

aware of any cost effective controls that 

can be used to address these relatively 

small emissions. 

b. NSPS for Pneumatic Controllers 

Pneumatic controllers are automated 

instruments used for maintaining a 

process condition, such as liquid level, 

pressure, pressure differential and 

temperature. Pneumatic controllers are 

widely used in the oil and natural gas 

sector. In many situations across all 

segments of the oil and gas industry, 

pneumatic controllers make use of the 

available high-pressure natural gas to 

operate. In these ‘‘gas-driven’’ 

pneumatic controllers, natural gas may 

be released with every valve movement 

or continuously from the valve control 

pilot. The rate at which this release 

occurs is referred to as the device bleed 

rate. Bleed rates are dependent on the 

design of the device. Similar designs 

will have similar steady-state rates 

when operated under similar 

conditions. Gas-driven pneumatic 

controllers are typically characterized as 

‘‘high-bleed’’ or ‘‘low-bleed,’’ where a 

high-bleed device releases more than 6 

standard cubic feet per hour (scfh) of 

gas, with 18 scfh bleed rate being what 

we used in our analyses below. There 

are three basic designs: (1) Continuous 

bleed devices (high or low-bleed) are 

used to modulate flow, liquid level or 

pressure and gas is vented at a steadystate rate; (2) actuating/intermittent 

devices (high or low-bleed) perform 

quick control movements and only 

release gas when they open or close a 

valve or as they throttle the gas flow; 

and (3) self-contained devices release 

gas to a downstream pipeline instead of 

to the atmosphere. We are not aware of 

any add-on controls that are or can be 

used to reduce VOC emissions from gasdriven pneumatic devices. 

For an average high-bleed pneumatic 

controller located in production (where 

the content of VOC in the raw product 

stream is relatively high), the difference 

in VOC emissions between a high-bleed 

controller and a low-bleed controller is 

around 1.8 tpy. For the transmission 

and storage segment (where the content 

of VOC in the pipeline quality gas is 

relatively low), the difference in VOC 

emissions between a high-bleed 

controller and a low-bleed controller is 

around 0.89 tpy. We have developed 

projections that estimate that 

approximately 13,600 new gas-driven 

units in the production segment and 67 

new gas-driven units in the 

transmission and storage segment will 

be installed each year, including 

replacement of old units. Not all 

pneumatic controllers are gas driven. 

These ‘‘non-gas driven’’ pneumatic 

controllers use sources of power other 

than pressurized natural gas, such as 

compressed ‘‘instrument air.’’ Because 

these devices are not gas driven, they do 

not release natural gas or VOC 

emissions, but they do have energy 

impacts because electrical power is 

required to drive the instrument air 

compressor system. Electrical service of 

at least 13.3 kilowatts (kW) is required 

to power a 10 horsepower (hp) 

instrument air compressor, which is a 

relatively small capacity compressor. At 

sites without available electrical service 

sufficient to power an instrument air 

compressor, only gas driven pneumatic 

devices can be used. During our review, 

we determined that gas processing 

plants are the only facilities in the oil 

and natural gas sector highly likely to 

have electrical service sufficient to 

power an instrument air system, and 

that approximately half of existing gas 

processing plants are using non-gas 

driven devices. 

For devices at gas processing plants, 

we evaluated the use of non-gas driven 

controllers and low-bleed controllers as 

options for reducing VOC emissions, 

with high-bleed controllers being the 

baseline. As mentioned above, non-gas 

driven devices themselves have zero 

emissions, but they do have energy 

impacts because electrical power is 

required to drive the instrument air 

compressor system. In our cost analysis, 

we determined that the annualized cost 

of installing and operating a fully 

redundant 10 hp (13.3 kW) instrument 

air system (systems generally are 

designed with redundancy to allow for 

system maintenance and failure without 

loss of air pressure), including duplicate 

compressors, air tanks and dryers, 

would be $11,090. A system of this size 

is capable of serving 15 control loops 

and reducing VOC emissions by 4.2 tpy, 

for a cost effectiveness of $2,659 per ton 

of VOC reduced. If the savings of the 

salable natural gas that would have been 

emitted is considered, the value of the 

gas not emitted would help offset the 

cost for this control, bringing the cost 

per ton of VOC down to $1,824. 

We also evaluated the use of lowbleed controllers in place of high-bleed 

controllers at processing plants. We 

evaluated the impact of bleeding 6 

standard cubic feet of natural gas per 

hour, which is the maximum bleed rate 

from low-bleed controllers, according to 

manufacturers of these devices. We 

chose natural gas as a surrogate for VOC, 

because manufacturers’ technical 

specifications for pneumatic controllers 

are stated in terms of natural gas bleed 

rate rather than VOC. The capital cost 

difference between a new high-bleed 

controller and a new low-bleed 

controller is estimated to be $165. 

Without taking into account the savings 

due to the natural gas losses avoided, 

the annual costs are estimated to be 

around $23 per year, which is a cost of 

$13 per ton of VOC reduced for the 

production segment. If the savings of the 

salable natural gas that would have been 

emitted is considered, there is a net 

savings of $1,519 per ton of VOC 

reduced. 

Although the non-gas-driven 

controller system is more expensive 

than the low-bleed controller system, it 

is still reasonably cost-effective. 

Furthermore, the non-gas-driven 

controller system achieves a 100-percent 

VOC reduction in contrast to a 66- 

percent reduction achieved by a lowbleed controller. Moreover, we believe 

the collateral emissions from electrical 

power generation needed to run the 

compressor are very low. Finally, nongas-driven pneumatic controllers avoid 

potentially explosive concentrations of 

natural gas which can occur as a result 

of normal bleeding from groups of gasdriven pneumatic controllers located in 

close proximity, as they often are at gas 

processing plants. Based on our review 

described above, we believe that a nongas-driven controller is BSER for 

reducing VOC emissions from 

pneumatic devices at gas processing 

plants. Accordingly, the proposed 

standard for pneumatic devices at gas 

processing plants is a zero VOC 

emission limit. 

For the production (other than 

processing plants) and transmission and 

storage segments, where electrical 

service sufficient to power an 

instrument air system is likely 


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Federal Register / Vol. 76, No. 163 / Tuesday, August 23, 2011 / Proposed Rules 52761 

unavailable and, therefore, only gasdriven devices can be used, we 

evaluated the use of low-bleed 

controllers in place of high-bleed 

controllers. Just as in our analysis of 

low-bleed controllers as an option for 

gas processing plants, we evaluated the 

impact of bleeding 6 standard cubic feet 

per minute (scfm) of natural gas per 

hour contrasted with 18 scfm from a 

high-bleed unit. Again, the capital cost 

difference between a new high-bleed 

controller and a new low-bleed 

controller is estimated to be $165. 

Without taking into account the savings 

due to the natural gas losses avoided, 

the annual costs are estimated to be 

around $23 per year, which is a cost of 

$13 per ton of VOC reduced for the 

production segment. If the savings of the 

salable natural gas that would have been 

emitted is considered, there is a net 

savings for this control. In the 

transmission and storage segment, 

where the VOC content of the vented 

gas is much lower than in the 

production segment, the cost 

effectiveness of a low-bleed pneumatic 

device is estimated to be around $262 

per ton of VOC reduced. However, there 

are no potential offsetting savings to be 

realized in the transmission and storage 

segment, since the operators of 

transmission and storage stations 

typically do not own the gas they are 

handling. Based on our evaluation of the 

emissions and costs, we believe that 

low-bleed controllers represent BSER 

for pneumatic controllers in the 

production (other than processing 

plants) and transmission and storage 

segments. Therefore, for pneumatic 

devices at these locations, we propose a 

natural gas bleed rate limit of 6.0 scfh 

to reflect the VOC limit with the use of 

a low-bleed controller. 

There may be situations where highbleed controllers and the attendant gas 

bleed rate greater than 6 cubic feet per 

hour, are necessary due to functional 

requirements, such as positive actuation 

or rapid actuation. An example would 

be controllers used on large emergency 

shutdown valves on pipelines entering 

or exiting compression stations. For 

such situations, we have provided in the 

proposed rule an exemption where 

pneumatic controllers meeting the 

emission standards discussed above 

would pose a functional limitation due 

to their actuation response time or other 

operating characteristics. We are 

requesting comments on whether there 

are other situations that should be 

considered for this exemption. If you 

provide such comment, please specify 

the criteria for such situations that 

would help assure that only appropriate 

exemptions are claimed. 

The proposed standards would apply 

to installation of a new pneumatic 

device (including replacing an existing 

device with a new device). We consider 

that a pneumatic device, an apparatus, 

is an affected facility and each 

installation is construction subject to 

the proposed NSPS. See definitions of 

‘‘affected facility’’ and ‘‘construction’’ at 

40 CFR 60.2. 

c. NSPS for Compressors 

There are many locations throughout 

the oil and natural gas sector where 

compression of natural gas is required to 

move it along the pipeline. This is 

accomplished by compressors powered 

by combustion turbines, reciprocating 

internal combustion engines or electric 

motors. Turbine-powered compressors 

use a small portion of the natural gas 

that they compress to fuel the turbine. 

The turbine operates a centrifugal 

compressor, which compresses the 

natural gas for transit through the 

pipeline. Sometimes an electric motor is 

used to turn a centrifugal compressor. 

This type of compressor does not 

require the use of any of the natural gas 

from the pipeline, but it does require a 

substantial source of electricity. 

Reciprocating spark ignition engines are 

also used to power many compressors, 

referred to as reciprocating compressors, 

since they compress gas using pistons 

that are driven by the engine. Like 

combustion turbines, these engines are 

fueled by natural gas from the pipeline. 

Both centrifugal and reciprocating 

compressors are sources of VOC 

emissions and were evaluated for 

coverage under the NSPS. 

Centrifugal Compressors. Centrifugal 

compressors require seals around the 

rotating shaft to minimize gas leakage 

and fugitive VOC emissions from where 

the shaft exits the compressor casing. 

There are two types of seal systems: Wet 

seal systems and mechanical dry seal 

systems. 

Wet seal systems use oil, which is 

circulated under high pressure between 

three or more rings around the 

compressor shaft, forming a barrier to 

minimize compressed gas leakage. Very 

little gas escapes through the oil barrier, 

but considerable gas is absorbed by the 

oil. The amount of gas absorbed and 

entrained by the oil barrier is affected by 

the operating pressure of the gas being 

handled; higher operating pressures 

result in higher absorption of gas into 

the oil. Seal oil is purged of the 

absorbed and entrained gas (using 

heaters, flash tanks and degassing 

techniques) and recirculated to the seal 

area for reuse. Gas that is purged from 

the seal oil is commonly vented to the 

atmosphere. Degassing of the seal oil 

emits an average of 47.7 scfm of gas, 

depending on the operating pressure of 

the compressor. An uncontrolled wet 

seal system can emit, on average, 

approximately 20.5 tpy of VOC during 

the venting process (production 

segment) or about 3.5 tpy (transmission 

and storage segment). We identified two 

potential control techniques for 

reducing emissions from degassing of 

wet seal systems: (1) Routing the gas 

back to a low pressure fuel stream to be 

combusted as fuel gas and (2) routing 

the gas to a flare. We know only of 

anecdotal, undocumented information 

on routing of the gas back to a fuel 

stream and, therefore, were unable to 

assess costs and cost effectiveness of the 

first option. Although we do not have 

specific examples of routing emissions 

from wet seal degassing to a flare, we 

were able to estimate the cost, emission 

reductions and cost effectiveness of the 

second option using uncontrolled wet 

seals as a baseline. 

Based on the average uncontrolled 

emissions of wet seal systems discussed 

above and a flare efficiency of 95 

percent, we determined that VOC 

emission reductions from a wet seal 

system would be an average of 19.5 tpy 

(production segment) or 3.3 tpy 

(transmission and storage segment). 

Using an annualized cost of flare 

installation and operation of $103,373, 

we estimated the incremental cost 

effectiveness of this option (from 

uncontrolled wet seals to controlled wet 

seals using a flare) to be approximately 

$5,300/ton and $31,000/ton for the 

production segment and transmission 

and storage segment, respectively. With 

this option, there would be secondary 

air impacts from combustion. However 

we did not identify any nonair quality 

or energy impacts associated with this 

control technique. 

Dry seal systems do not use any 

circulating seal oil. Dry seals operate 

mechanically under the opposing force 

created by hydrodynamic grooves and 

springs. Fugitive emissions occur from 

dry seals around the compressor shaft. 

Based on manufacturer studies and 

engineering design estimates, fugitive 

emissions from dry seal systems are 

approximately 6 scfm of gas, depending 

on the operating pressure of the 

compressor. A dry seal system can have 

fugitive emissions of, on average, 

approximately 2.6 tpy of VOC 

(production segment) or about 0.4 tpy 

(transmission and storage segment). We 

did not identify any control device 

suitable to capture and control the 

fugitive emissions from dry seals around 

the compressor shaft. 


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52762 Federal Register / Vol. 76, No. 163 / Tuesday, August 23, 2011 / Proposed Rules 

Using uncontrolled wet seals as a 

baseline, we evaluated the reductions 

and incremental cost effectiveness of 

dry seal systems. Based on the average 

fugitive emissions, we determined that 

VOC emission reductions achieved by 

dry seal systems compared to 

uncontrolled wet seal systems would be 

18 tpy (production segment) and 3.1 tpy 

(transmission and storage segment). 

Combined with an annualized cost of 

dry seal systems of $10,678, the 

incremental cost effectiveness compared 

to uncontrolled wet seal systems would 

be $595/ton and $3,495/ton for the 

production segment and transmission 

and storage segment, respectively. We 

identified neither nonair quality nor any 

energy impacts associated with this 

option. 

In performing our analysis, we 

estimated the incremental cost of a dry 

seal compressor over that of an 

equivalent wet seal compressor to be 

$75,000. This value was obtained from 

a vendor who represents a large share of 

the market for centrifugal compressors. 

However, this number likely represents 

a conservatively high value because wet 

seal units have a significant amount of 

ancillary equipment, namely the seal oil 

system and, thus, additional capital 

expenses. Dry seal systems have some 

ancillary equipment (the seal gas 

filtration system), but the costs are less 

than the wet seal oil system. We were 

not able to directly confirm this 

assumption with the vendor, however, a 

search of product literature showed that 

seal oil systems and seal gas filtration 

systems are typically listed separate 

from the basic compressor package. 

Using available data on the cost of this 

equipment, it is very likely that the cost 

of purchasing a dry seal compressor 

may actually be lower that a wet seal 

compressor. We seek comment on 

available cost data of a dry seal versus 

wet seal compressor, including all 

ancillary equipment costs. 

In light of the above analyses, we 

propose to determine that dry seal 

systems are BSER for reducing VOC 

emissions from centrifugal compressors. 

We evaluated the possibility of setting a 

performance standard that reflects the 

emission limitation achievable through 

the use of a dry seal system. However, 

as mentioned above, VOC from 

centrifugal compressors with dry seals 

are fugitive emissions from around the 

compressor shafts. There is no device to 

capture and control these fugitive 

emissions, nor can reliable 

measurement of these emissions be 

conducted due to difficulty in accessing 

the leakage area and danger of 

contacting the shaft rotating at 

approximately 30,000 revolutions per 

minute. This not only poses a likely 

hazard that would destroy test 

equipment on contact, it poses a safety 

hazard to personnel, as well. Therefore, 

pursuant to section 111(h)(2) of the 

CAA, we are proposing an equipment 

standard that would require the use of 

dry seals to limit the VOC emissions 

from new centrifugal compressors. We 

consider that a centrifugal compressor, 

an apparatus, is an affected facility and 

each installation is construction subject 

to the proposed NSPS. See definitions of 

‘‘affected facility’’ and ‘‘construction’’ at 

40 CFR 60.2. Accordingly, the proposed 

standard would apply to installation of 

new centrifugal compressors at new 

locations, as well as replacement of old 

compressors. 

Although we are proposing to 

determine dry seal systems to be BSER 

for centrifugal compressors, we are 

soliciting comments on the emission 

reduction potential, cost and any 

limitations for the option of routing the 

gas back to a low pressure fuel stream 

to be combusted as fuel gas. In addition, 

we solicit comments on whether there 

are situations or applications where wet 

seal is the only option, because a dry 

seal system is infeasible or otherwise 

inappropriate. 

Reciprocating Compressors. 

Reciprocating compressors in the 

natural gas industry leak natural gas 

fugitive VOC during normal operation. 

The highest volumes of gas loss and 

fugitive VOC emissions are associated 

with piston rod packing systems. 

Packing systems are used to maintain a 

tight seal around the piston rod, 

preventing the high pressure gas in the 

compressor cylinder from leaking, while 

allowing the rod to move freely. This 

leakage rate is dependent on a variety of 

factors, including physical size of the 

compressor piston rod, operating speed 

and operating pressure. Under the best 

conditions, new packing systems 

properly installed on a smooth, wellaligned shaft can be expected to leak a 

minimum of 11.5 scfh. Higher leak rates 

are a consequence of fit, alignment of 

the packing parts and wear. 

We evaluated the possibility of 

reducing VOC emissions from reciprocal 

compressors through a control device. 

However, VOC from reciprocating 

compressors are fugitive emissions from 

around the compressor shafts. Although 

it is possible to construct an enclosure 

around the rod packing area and vent 

the emissions outside for safety 

purposes, connection to a closed vent 

system and control device would create 

back pressure on the leaking gas. This 

back pressure would cause the leaked 

gas instead to be forced inside the 

crankcase of the engine, which would 

dilute lubricating oil, causing premature 

failure of engine bearings, pose an 

explosion hazard and eventually be 

vented from the crankcase breather, 

defeating the purpose of a control 

device. 

As mentioned above, as packing 

wears and deteriorates, leak rates can 

increase. We, therefore, evaluate 

replacement of compressor rod packing 

systems as an option for reducing VOC 

emissions. Conventional bronzemetallic packing rings wear out and 

need to be replaced every 3 to 5 years, 

depending on the compressor’s rate of 

usage (i.e., the percentage of time that a 

compressor is in pressurized mode). 

Based on industry experience in the 

Natural Gas STAR program and other 

sources, we evaluated the rod packing 

replacement costs for reciprocating 

compressors at different segments of 

this industry. Usage rates vary by 

segment. Usage rates for compressors at 

wellheads, gathering/boosting stations, 

processing plants, transmission stations 

and storage facilities are 100, 79, 90, 79 

and 68 percent, respectively. 

Reciprocating compressors at wellheads 

are small and operate at lower 

pressures, which limit VOC emissions 

from these sources. Due to the low VOC 

emissions from these compressors, 

about 0.044 tpy, combined with an 

annual cost of approximately $3,700, 

the cost per ton of VOC reduction is 

rather high. We estimated that the cost 

effectiveness of controlling wellhead 

compressors is over $84,000 per ton of 

VOC reduced, which we believe to be 

too high and, therefore, not reasonable. 

Because the cost effectiveness of 

replacing packing wellhead compressor 

rod systems is not reasonable, and 

absent other emission reduction 

measures, we did not find a BSER for 

reducing VOC emissions from reciprocal 

compressors at wellheads. 

For reciprocating compressors located 

at other oil and gas operations, we 

estimated that the cost effectiveness of 

controlling compressor VOC emissions 

by rod packing replacement would be 

$870 per ton of VOC for reciprocating 

compressors at gathering and boosting 

stations, $270 per ton of VOC for 

reciprocating compressors at processing 

stations, $2,800 per ton of VOC for 

reciprocating compressors at 

transmission stations and $3,700 per ton 

of VOC for reciprocating compressors at 

underground storage facilities. We 

consider these costs to be reasonable. 

We did not identify any nonair quality 

health or environmental impacts or 

energy impacts associated with rod 

packing replacement. In light of the 

above, we propose to determine that 

such control is the BSER for reducing 


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VOC emission from compressors at 

these other oil and gas operations. 

Because VOC emitted from reciprocal 

compressors are fugitive emissions, 

there is no device to capture and control 

the emissions. Therefore, pursuant to 

section 111(h) of the CAA, we are 

proposing an operational standard. 

Based on industry experience reported 

to the Natural Gas STAR program, we 

determined that packing rods should be 

replaced every 3 years of operation. 

However, to account for segments of the 

industry in which reciprocating 

compressors operate in pressurized 

mode a fraction of the calendar year 

(ranging from approximately 68 percent 

up to approximately 90 percent), the 

proposed rule expresses the 

replacement requirement in terms of 

hours of operation rather than on a 

calendar year basis. One year of 

continuous operation would be 8,760 

hours. Three years of continuous 

operation would be 26,280 hours, or 

rounded to the nearest thousand, 26,000 

hours. Accordingly, the proposed rule 

would require the replacement of the 

rod packing every 26,000 hours of 

operation. The owner or operator would 

be required to monitor the hours of 

operation beginning with the 

installation of the reciprocating 

compressor affected facility. Cumulative 

hours of operation would be reported 

each year in the facility’s annual report. 

Once the hours of operation reached 

26,000 hours, the owner or operator 

would be required to change the rod 

packing immediately, although 

unexpected shutdowns could be 

avoided by tracking hours of operation 

and planning for packing replacement at 

scheduled maintenance shutdowns 

before the hours of operation reached 

26,000. 

Some industry partners of the Natural 

Gas STAR program currently conduct 

periodic testing to determine the leakage 

rates that would identify economically 

beneficial replacement of rod packing 

based on natural gas savings. Therefore, 

we are soliciting comments on 

incorporating a method similar to that 

in the Natural Gas STAR’s Lessons 

Learned document entitled, Reducing 

Methane Emissions from Compressor 

Rod Packing Systems (http:// 

www.epa.gov/gasstar/documents/ 

ll_rodpack.pdf), to be incorporated in 

the NSPS. We are soliciting comments 

on how to determine a suitable leak 

threshold above which rod packing 

replacement would be cost effective for 

VOC emission reduction. We are also 

soliciting comment on the appropriate 

replacement frequency and other 

considerations that would be associated 

with regular replacement periods. 

d. NSPS for Storage Vessels 

Crude oil, condensate and produced 

water are typically stored in fixed-roof 

storage vessels. Some vessels used for 

storing produced water may be open-top 

tanks. These vessels, which are operated 

at or near atmospheric pressure 

conditions, are typically located as part 

of a tank battery. A tank battery refers 

to the collection of process equipment 

used to separate, treat and store crude 

oil, condensate, natural gas and 

produced water. The extracted products 

from productions wells enter the tank 

battery through the production header, 

which may collect product from many 

wells. 

Emissions from storage vessels are a 

result of working, breathing and flash 

losses. Working losses occur due to the 

emptying and filling of storage tanks. 

Breathing losses are the release of gas 

associated with daily temperature 

fluctuations and other equilibrium 

effects. Flash losses occur when a liquid 

with dissolved gases is transferred from 

a vessel with higher pressure to a vessel 

with lower pressure, thus, allowing 

dissolved gases and a portion of the 

liquid to vaporize or flash. In the oil and 

natural gas production segment, flashing 

losses occur when live crude oils or 

condensates flow into a storage tank 

from a processing vessel operated at a 

higher pressure. Typically, the larger the 

pressure drop, the more flash emissions 

will occur in the storage stage. 

Temperature of the liquid also 

influences the amount of flash 

emissions. The amount of liquid 

entering the tank during a given time, 

commonly known as throughput, also 

affects the emission rate, with higher 

throughput tanks having higher annual 

emissions, given that other parameters 

are the same. 

In analyzing controls for storage 

vessels, we reviewed control techniques 

identified in the Natural Gas STAR 

program and state regulations. We 

identified two ways of controlling 

storage vessel emissions, both of which 

can reduce VOC emissions by 95 

percent. One option would be to install 

a vapor recovery unit (VRU) and recover 

all the vapors from the tanks. The other 

option would be to route the emissions 

from the tanks to a flare control device. 

These devices could be ‘‘candlestick’’ 

flares that are found at gas processing 

plants or other larger facilities or 

enclosed combustors which are 

commonly found at smaller field 

facilities. We estimated the total annual 

cost for a VRU to be approximately 

$18,900/yr and for a flare to be 

approximately $8,900/yr. Cost 

effectiveness of these control options 

depend on the amount of vapor 

produced by the storage vessels being 

controlled. A VRU has a potential 

advantage over flaring, in that it 

recovers hydrocarbon vapors that 

potentially can be used as supplemental 

burner fuel, or the vapors can be 

condensed and collected as condensate 

that can be sold. If natural gas is 

recovered, it can be sold, as well, as 

long as a gathering line is available to 

convey the recovered salable gas 

product to market or to further 

processing. A VRU also does not have 

secondary air impacts that flaring does, 

as described below. However, a VRU 

cannot be used in all instances. Some 

conditions that affect the feasibility of 

VRU are: Availability of electrical 

service sufficient to power the VRU; 

fluctuations in vapor loading caused by 

surges in throughput and flash 

emissions from the tank; potential for 

drawing air into condensate tanks 

causing an explosion hazard; and lack of 

appropriate destination or use for the 

vapor recovered. 

Like a VRU, a flare control device can 

also achieve a control efficiency of 95 

percent. There are no technical 

limitations on the use of flares to control 

vapors from condensate and crude oil 

tanks. However, flaring has a secondary 

impact from emissions of NOX and other 

pollutants. In light of the technical 

limitations with the use of a VRU, we 

are unable to conclude that a VRU is 

better than flaring. We, therefore, 

propose to determine that both a VRU 

and flare are BSER for reducing VOC 

emission from storage vessels. We 

propose an NSPS of 95-percent 

reduction for storage vessels to reflect 

the level of emission reduction 

achievable by VRU and flares. 

VOC emissions from storage vessels 

vary significantly, depending on the rate 

of liquid entering and passing through 

the vessel (i.e., its throughput), the 

pressure of the liquid as it enters the 

atmospheric pressure storage vessel, the 

liquid’s volatility and temperature of the 

liquid. Some storage vessels have 

negligible emissions, such as those with 

very little throughput and/or handling 

heavy liquids entering at atmospheric 

pressure. We do not believe that it is 

cost effective to control these vessels. 

We believe it is important to control 

tanks with significant VOC emissions 

under the proposed NSPS. 

In our analysis, we evaluated storage 

tanks with varying condensate or crude 

oil throughput. We used emission 

factors developed for the Texas 

Environmental Research Consortium in 

a study that evaluated VOC emissions 

from crude oil and condensate storage 

tanks by performing direct 


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measurements. The study found that the 

average VOC emission factor for crude 

oil storage tanks was 1.6 pounds (lb) 

VOC per barrel of crude oil throughput. 

The average VOC emission factor for 

condensate tanks was determined to be 

33.3 lb VOC per barrel of condensate 

throughput. Applying these emission 

factors and evaluating condensate 

throughput rates of 0.5, 1, 2 and 5 

barrels per day (bpd), we determined 

that VOC emissions at these condensate 

throughput rates would be 

approximately 3, 6, 12 and 30 tpy, 

respectively. Similarly, we evaluated 

crude oil throughput rates of 1, 5, 20 

and 50 bpd. Based on the Texas study, 

these crude oil throughput rates would 

result in VOC emissions of 0.3, 1.5, 5.8 

and 14.6 tpy, respectively. We believe 

that it is important to control tanks with 

significant VOC emissions. 

Furthermore, we believe it would be 

easier and less costly for owners and 

operators to determine applicability by 

using a throughput threshold instead of 

an emissions threshold. As a result of 

the above analyses, we believe that 

storage vessels with at least 1 bpd of 

condensate or 20 bpd of crude oil 

should be controlled. These throughput 

rates are equivalent to VOC emissions of 

approximately 6 tpy. Based on an 

estimated annual cost of $18,900 for the 

control device, controlling storage 

vessels with these condensate or crude 

oil throughputs would result in a cost 

effectiveness of $3,150 per ton of VOC 

reduced. 

Based on our evaluation, we propose 

to determine that both a VRU and flare 

are BSER for reducing VOC emission 

from storage vessels with throughput of 

at least 1 barrel of condensate per day 

or 20 barrels of crude oil per day. We 

propose an NSPS of 95-percent 

reduction for these storage vessels to 

reflect the level of emission reduction 

achievable by VRU and flare control 

devices. 

For storage vessels below the 

throughput levels described above 

(‘‘small throughput tanks’’), for which 

we do not consider flares or VRU to be 

cost effective controls, we evaluated 

other measures to reduce VOC 

emissions. Standard practices for such 

tanks include requiring a cover that is 

well designed, maintained in good 

condition and kept closed. Crude oil 

and condensate storage tanks in the oil 

and natural gas sector are designed to 

operate at or just slightly above or below 

atmospheric pressure. Accordingly, they 

are provided with vents to prevent tank 

destruction under rapid pressure 

increases due to flash emissions 

conditions. Studies by the Natural Gas 

STAR program and by others have 

shown that working losses (i.e., those 

emissions absent flash emission 

conditions) are very low, approaching 

zero. During times of flash emissions, 

tanks are designed such that the flash 

emissions are released through a vent on 

the fixed roof of the tank when pressure 

reaches just a few ounces to prevent 

pressure buildup and resulting tank 

damage. At those times, vapor readily 

escapes through the vent to protect the 

tank. Tests have shown that open 

hatches or leaking hatch gaskets have 

little effect on emissions from 

uncontrolled tanks due to the 

functioning roof vent. However, in the 

case of controlled tanks, the control 

requirements include provisions for 

maintaining integrity of the closed vent 

system that conveys emissions to the 

control device, including hatches and 

other tank openings. As a result, hatches 

are required to be kept closed and 

gaskets kept in good repair to meet 

control requirements of controlled 

storage vessels. Because the measures 

we evaluated, including maintenance of 

hatch integrity, do not provide 

appreciable emission reductions for 

storage vessels with throughputs under 

1 barrel of condensate per day and 21 

barrels of crude oil per day, we believe 

that the control options we evaluated do 

not reflect BSER for the small 

throughput tanks and we are not 

proposing standards for these tanks. 

As discussed in section VII of this 

preamble, we are proposing to amend 

the NESHAP for oil and natural gas 

production facilities at 40 CFR part 63, 

subpart HH to require that all storage 

vessels at production facilities reduce 

HAP emissions by 95 percent. Because 

the controls used to achieve the 95- 

percent HAP reduction are the same as 

the proposed BSER for VOC reduction 

for storage vessels (i.e., VRU and flare), 

sources that are achieving the 95- 

percent HAP reduction would also be 

meeting the proposed NSPS of 95- 

percent VOC reduction. In light of the 

above, and to avoid duplicate 

monitoring, recordkeeping and 

reporting, we propose that storage 

vessels subject to the requirements of 

subpart HH are exempt from the 

proposed NSPS for storage vessel in 40 

CFR part 60, subpart OOOO. 

e. NSPS for VOC Equipment Leaks 

Equipment leaks are fugitive 

emissions emanating from valves, pump 

seals, flanges, compressor seals, 

pressure relief valves, open-ended lines 

and other process and operation 

components. There are several potential 

reasons for equipment leak emissions. 

Components such as pumps, valves, 

pressure relief valves, flanges, agitators 

and compressors are potential sources 

that can leak due to seal failure. Other 

sources, such as open-ended lines and 

sampling connections may leak for 

reasons other than faulty seals. In 

addition, corrosion of welded 

connections, flanges, and valves may 

also be a cause of equipment leak 

emissions. Because of the large number 

of valves, pumps and other components 

within an oil and gas production, 

processing and transmission facility, 

equipment leak volatile emissions from 

these components can be significant. 

Natural gas processing plants, especially 

those using refrigerated absorption and 

transmission stations tend to have a 

large number of components. 

Equipment leaks from processing plants 

are addressed in our review of 40 CFR 

part 60, subpart KKK, which is 

discussed above in section VI.B.1. 

In addition to gas processing plants, 

these types of equipment also exist at oil 

and gas production sites and gas 

transmission and storage facilities. 

While the number of components at 

individual transmission and storage 

facilities is relatively smaller than at 

processing plants, collectively, there are 

many components that can result in 

significant emissions. 

Therefore, we evaluated applying 

NSPS for equipment leaks to facilities in 

the production segment of the industry, 

which includes everything from the 

wellhead to the point that the gas enters 

the processing plant, transmission 

pipeline or distribution pipeline. 

Production facilities can vary 

significantly in the operations 

performed and the processes, all of 

which impact the number of 

components and potential emissions 

from leaking equipment and, thus, 

impact the annual costs related to 

implementing a LDAR program. We 

used data collected by the Gas Research 

Institute to develop model production 

facilities. Baseline emissions, along with 

emission reductions and costs of 

regulatory alternatives, were estimated 

using these model production facilities. 

We considered production facilities 

where separation, storage, compression 

and other processes occur. These 

facilities may not have a wellhead onsite, but would be associated with a 

wellhead. We also evaluated gathering 

and boosting facilities, where gas and/ 

or oil are collected from a number of 

wells, then processed and transported 

downstream to processing plants or 

transmission stations. We evaluated the 

impacts at these production facilities 

with varying number of operations and 

equipment. We also developed a model 

plant for the transmission and storage 

segment using data from the Gas 


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13Because optical gas imaging is used to view 

several pieces of equipment at a facility at once to 

survey for leaks, options involving imaging are not 

amenable to a component by component analysis. 

Research Institute. Details of these 

evaluations may be found in the TSD in 

the docket. 

For an average production site at or 

associated with a wellhead, we 

estimated annual VOC emissions from 

equipment leaks of around 2.6 tpy. For 

an average gathering/boosting facility, 

we estimated the annual VOC emissions 

from equipment leaks to be around 9.8 

tpy. The average transmission and 

storage facility emits 2.7 tpy of VOC. 

For facilities in each non-gas 

processing plant segment, we evaluated 

the same four options as we did for gas 

processing plants in section VI.B.1 

above. These four options are as follows: 

(1) 40 CFR part 60, subpart VVa-level 

LDAR (which is based on conducting 

Method 21 monthly, defining ‘‘leak’’ at 

500 ppm threshold, and adding 

connectors to the VV list of components 

to be monitored); (2) monthly optical 

gas imaging with annual Method 21 

check (the alternative work practice for 

monitoring equipment for leaks at 40 

CFR 60.18(g)); (3) monthly optical gas 

imaging alone; and (4) annual optical 

gas imaging alone. 

For option 1, we evaluated subpart 

VVa-LDAR as a whole. We also 

analyzed separately the individual types 

of components (valves, connectors, 

pressure relief devices and open-ended 

lines). Detailed discussions of these 

component by component analyses are 

included in the TSD in the docket. 

Based on our evaluation, subpart VValevel LDAR (Option 1) results in more 

VOC reduction than the subpart VVlevel LDAR currently required for gas 

processing plants, because more leaks 

are found based on the lower definition 

of ‘‘leak’’ under subpart VVa (10,000 

ppm for subpart VV and 500 ppm for 

subpart VVa). In addition, our 

evaluation shows that the cost per ton 

of VOC reduced for subpart VVa level 

controls is less than the cost per ton of 

VOC reduced for the less stringent 

subpart VV level of control. Although 

the cost of repairing more leaks is 

higher, the increased VOC control 

afforded by subpart VVa level controls 

more than offsets the increased costs. 

For the subpart VVa level of control 

at the average production site associated 

with a wellhead, average facility-wide 

cost-effectiveness would be $16,084 per 

ton of VOC. Component-specific costeffectiveness ranged from $15,063 per 

ton of VOC (for valves) to $211,992 per 

ton of VOC (for pressure relief devices), 

with connectors and open-ended lines 

being $74,283 and $180,537 per ton of 

VOC, respectively. We also looked at 

component costs for a modified subpart 

VVa level of control with less frequent 

monitoring for valves and connectors at 

production sites associated with a 

wellhead.12 The cost-effectiveness for 

valves was calculated to be $17,828 per 

ton of VOC by reducing the monitoring 

frequency from monthly to annually. 

The cost-effectiveness for connectors 

was calculated to be $87,277 per ton of 

VOC by reducing the monitoring 

frequency from every 4 years to every 8 

years after the initial compliance period. 

We performed a similar facility-wide 

and component-specific analysis of 

option 1 LDAR for gathering and 

boosting stations. For the subpart VVa 

level of control at the average gathering 

and boosting station, facility-wide costeffectiveness was estimated to be $9,344 

per ton of VOC. Component-specific 

cost-effectiveness ranged from $6,079 

per ton of VOC (for valves) to $77,310 

per ton of VOC (for open-ended lines), 

with connectors and pressure relief 

devices being $23,603 and $72,523 per 

ton, respectively. For the modified 

subpart VVa level of control at gathering 

and boosting stations, cost-effectiveness 

ranged from $5,221 per ton of VOC (for 

valves) to $77,310 per ton of VOC (for 

open-ended lines), with connectors and 

pressure relief devices being $27,274 

and $72,523 per ton, respectively. The 

modified subpart VVa level controls 

were more cost-effective than the 

subpart VVa level controls for valves, 

but not for connectors. This is due to the 

low cost of monitoring connectors and 

the low VOC emissions from leaking 

connectors. 

We also performed a similar analysis 

of option 1 subpart VVa-level LDAR for 

gas transmission and storage facilities. 

For the subpart VVa level of control at 

the average transmission and storage 

facility, facility-wide cost-effectiveness 

was $20,215. Component-specific costeffectiveness ranged from $24,762 per 

ton of VOC (for open-ended lines) to 

$243,525 per ton of VOC (for pressure 

relief devices), with connectors and 

valves being $36,527 and $43,111 per 

ton of VOC, respectively. For the 

modified subpart VVa level of control at 

transmission and storage facilities, costeffectiveness ranged from $24,762 per 

ton of VOC (for open-ended lines) to 

$243,525 per ton of VOC (for pressure 

relief devices), with connectors and 

valves being $42,140 and $40,593 per 

ton of VOC, respectively. Again, the 

modified subpart VVa level controls 

were more cost-effective for valves and 

less cost effective for connectors than 

the subpart VVa level controls. This is 

due to the low cost of monitoring 

connectors and the low VOC emissions 

from leaking connectors. 

For each of the non-gas processing 

segments, we also evaluated monthly 

optical gas imaging with annual Method 

21 check (Option 2). As discussed in 

secton VI.B.1, we had previously 

determined that the VOC reductions 

achieved under this option would be the 

same as for option 1 subpart VVa-level 

LDAR. In our evaluation of Option 2, we 

estimated that a single optical imaging 

instrument could be used for 160 well 

sites and 13 gathering and boosting 

stations, which means that the cost of 

the purchase or rental of the camera 

would be spread across 173 facilities. 

For production sites, gathering and 

boosting stations, and transmission and 

storage facilities, we estimated that 

option 2 monthly optical gas imaging 

with annual Method 21 check would 

have cost-effectiveness of $16,123, 

$10,095, and $19,715 per ton of VOC, 

respectively.13

The annual costs for option 1 and 

option 2 leak detection and repair 

programs for production sites associated 

with a wellhead, gathering and boosting 

stations and transmission and storage 

facilities were higher than those 

estimated for natural gas processing 

plants because natural gas processing 

plant annual costs are based on the 

incremental cost of implementing 

subpart VVa-level standards, whereas 

the other facilities are not currently 

regulated under an LDAR program. The 

currently unregulated sites would be 

required to set up a new LDAR program; 

perform initial monitoring, tagging, 

logging and repairing of components; as 

well as planning and training personnel 

to implement the new LDAR program. 

In addition to options 1 and 2, we 

evaluated a third option that consisted 

of monthly optical gas imaging without 

an annual Method 21 check. Because we 

were unable to estimate the VOC 

emissions achieved by an optical 

imaging program alone, we were unable 

to estimate the cost-effectiveness of this 

option. However, we estimated the 

annual cost of the monthly optical gas 

imaging LDAR program at production 

sites, gathering and boosting stations, 

and transmission and storage facilities 

to be $37,049, $86,135, and $45,080, 

respectively, based on camera purchase, 

or $32,693, $81,780, and $40,629, 

respectively, based on camera rental. 

Finally, we evaluated a fourth option 

similar to the third option except that 

the optical gas imaging would be 

performed annually rather than 

monthly. For this option, we estimated 

the annual cost for production sites, 

gathering and boosting stations, and 

transmission and storage facilities to be 


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$30,740, $64,416, and $24,031, 

respectively, based on camera purchase, 

or $26,341, $60,017, and $19,493, 

respectively, based on camera rental. 

We request comment on the 

applicability of a leak detection and 

repair program based solely on the use 

of optical imaging or other technologies. 

Of most use to us would be information 

on the effectiveness of advanced 

measurement technologies to detect and 

repair small leaks on the same order or 

smaller as specified in the VVa 

equipment leak requirements and the 

effects of increased frequency of and 

associated leak detection, recording, and 

repair practices. 

Based on the evaluation described 

above, we believe that neither option 1 

nor option 2 is cost effective for 

reducing fugitive VOC emissions from 

equipment leaks at sites, gathering and 

boosting stations, and transmission and 

storage facilities. For options 3 and 4, 

we were unable to estimate their cost 

effectiveness and, therefore, could not 

identify either of these two options as 

BSER for addressing equipment leak of 

VOC at production facilities associated 

with wellheads, at gathering and 

boosting stations or at gas transmission 

and storage facilities. We are, therefore, 

not proposing NSPS for addressing VOC 

emissions from equipment leaks at these 

facilities. 

5. What are the SSM provisions? 

The EPA is proposing standards in 

this rule that apply at all times, 

including during periods of startup or 

shutdown, and periods of malfunction. 

In proposing the standards in this rule, 

the EPA has taken into account startup 

and shutdown periods. 

The General Provisions in 40 CFR part 

60 require facilities to keep records of 

the occurrence and duration of any 

startup, shutdown or malfunction (40 

CFR 60.7(b)) and either report to the 

EPA any period of excess emissions that 

occurs during periods of SSM (40 CFR 

60.7(c)(2)) or report that no excess 

emissions occurred (40 CFR 60.7(c)(4)). 

Thus, any comments that contend that 

sources cannot meet the proposed 

standard during startup and shutdown 

periods should provide data and other 

specifics supporting their claim. 

Periods of startup, normal operations 

and shutdown are all predictable and 

routine aspects of a source’s operations. 

However, by contrast, malfunction is 

defined as a ‘‘sudden, infrequent, and 

not reasonably preventable failure of air 

pollution control and monitoring 

equipment, process equipment or a 

process to operate in a normal or usual 

manner * * *’’ (40 CFR 60.2.) The EPA 

has determined that malfunctions 

should not be viewed as a distinct 

operating mode and, therefore, any 

emissions that occur at such times do 

not need to be factored into 

development of CAA section 111 

standards. Further, nothing in CAA 

section 111 or in case law requires that 

the EPA anticipate and account for the 

innumerable types of potential 

malfunction events in setting emission 

standards. See, Weyerhaeuser v Costle, 

590 F.2d 1011, 1058 (D.C. Cir. 1978) 

(‘‘In the nature of things, no general 

limit, individual permit, or even any 

upset provision can anticipate all upset 

situations. After a certain point, the 

transgression of regulatory limits caused 

by ‘uncontrollable acts of third parties,’ 

such as strikes, sabotage, operator 

intoxication or insanity, and a variety of 

other eventualities, must be a matter for 

the administrative exercise of case-bycase enforcement discretion, not for 

specification in advance by 

regulation.’’), and, therefore, any 

emissions that occur at such times do 

not need to be factored into 

development of CAA section 111 

standards. 

Further, it is reasonable to interpret 

CAA section 111 as not requiring the 

EPA to account for malfunctions in 

setting emissions standards. For 

example, we note that CAA section 111 

provides that the EPA set standards of 

performance which reflect the degree of 

emission limitation achievable through 

‘‘the application of the best system of 

emission reduction’’ that the EPA 

determines is adequately demonstrated. 

Applying the concept of ‘‘the 

application of the best system of 

emission reduction’’ to periods during 

which a source is malfunctioning 

presents difficulties. The ‘‘application of 

the best system of emission reduction’’ 

is more appropriately understood to 

include operating units in such a way as 

to avoid malfunctions. 

Moreover, even if malfunctions were 

considered a distinct operating mode, 

we believe it would be impracticable to 

take malfunctions into account in 

setting CAA section 111 standards for 

affected facilities under 40 CFR part 60, 

subpart OOOO. As noted above, by 

definition, malfunctions are sudden and 

unexpected events and it would be 

difficult to set a standard that takes into 

account the myriad different types of 

malfunctions that can occur across all 

sources in the category. Moreover, 

malfunctions can vary in frequency, 

degree and duration, further 

complicating standard setting. 

In the event that a source fails to 

comply with the applicable CAA section 

111 standards as a result of a 

malfunction event, the EPA would 

determine an appropriate response 

based on, among other things, the good 

faith efforts of the source to minimize 

emissions during malfunction periods, 

including preventative and corrective 

actions, as well as root cause analyses 

to ascertain and rectify excess 

emissions. The EPA would also 

consider whether the source’s failure to 

comply with the CAA section 111 

standard was, in fact, ‘‘sudden, 

infrequent, not reasonably preventable’’ 

and was not instead ‘‘caused in part by 

poor maintenance or careless 

operation.’’ 40 CFR 60.2 (definition of 

malfunction). 

Finally, the EPA recognizes that even 

equipment that is properly designed and 

maintained can sometimes fail. Such 

failure can sometimes cause an 

exceedance of the relevant emission 

standard (See, e.g., State 

Implementation Plans: Policy Regarding 

Excessive Emissions During 

Malfunctions, Startup, and Shutdown 

(September 20, 1999); Policy on Excess 

Emissions During Startup, Shutdown, 

Maintenance, and Malfunctions 

(February 15, 1983)). The EPA is, 

therefore, proposing to add an 

affirmative defense to civil penalties for 

exceedances of emission limits that are 

caused by malfunctions. See 40 CFR 

60.41Da (defining ‘‘affirmative defense’’ 

to mean, in the context of an 

enforcement proceeding, a response or 

defense put forward by a defendant, 

regarding which the defendant has the 

burden of proof and the merits of which 

are independently and objectively 

evaluated in a judicial or administrative 

proceeding). We also are proposing 

other regulatory provisions to specify 

the elements that are necessary to 

establish this affirmative defense; the 

source must prove by a preponderance 

of the evidence that it has met all of the 

elements set forth in 40 CFR 60.46Da. 

(See 40 CFR 22.24). These criteria 

ensure that the affirmative defense is 

available only where the event that 

causes an exceedance of the emission 

limit meets the narrow definition of 

malfunction in 40 CFR 60.2 (sudden, 

infrequent, not reasonably preventable 

and not caused by poor maintenance 

and or careless operation). For example, 

to successfully assert the affirmative 

defense, the source must prove by a 

preponderance of the evidence that 

excess emissions ‘‘[w]ere caused by a 

sudden, infrequent, and unavoidable 

failure of air pollution control and 

monitoring equipment, process 

equipment, or a process to operate in a 

normal or usual manner * * *’’ The 

criteria also are designed to ensure that 

steps are taken to correct the 


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malfunction, to minimize emissions in 

accordance with 40 CFR 60.40Da and to 

prevent future malfunctions. For 

example, the source would have to 

prove by a preponderance of the 

evidence that ‘‘[r]epairs were made as 

expeditiously as possible when the 

applicable emission limitations were 

being exceeded * * *’’ and that ‘‘[a]ll 

possible steps were taken to minimize 

the impact of the excess emissions on 

ambient air quality, the environment 

and human health * * *’’ In any 

judicial or administrative proceeding, 

the Administrator may challenge the 

assertion of the affirmative defense and, 

if the respondent has not met the 

burden of proving all of the 

requirements in the affirmative defense, 

appropriate penalties may be assessed 

in accordance with CAA section 113 

(see also 40 CFR part 22.77). 

VII. Rationale for Proposed Action for 

NESHAP 

A. What data were used for the NESHAP 

analyses? 

To perform the technology review and 

residual risk analysis for the two 

NESHAP, we created a comprehensive 

dataset (i.e., the MACT dataset). This 

dataset was based on the EPA’s 2005 

National Emissions Inventory (NEI). The 

NEI database contains information about 

sources that emit criteria air pollutants 

and their precursors and HAP. The 

database includes estimates of annual 

air pollutant emissions from point, 

nonpoint and mobile sources in the 50 

states, the District of Columbia, Puerto 

Rico and the Virgin Islands. The EPA 

collects information about sources and 

releases an updated version of the NEI 

database every 3 years. 

The NEI database is compiled from 

these primary sources: 

• Emissions inventories compiled by 

state and local environmental 

agencies 

• Databases related to the EPA’s MACT 

programs 

• Toxics Release Inventory data 

• For electric generating units, the 

EPA’s Emission Tracking System/ 

CEM data and United States 

Department of Energy (DOE) fuel use 

data 

• For onroad sources, the United States 

Federal Highway Administration’s 

estimate of vehicle miles traveled and 

emission factors from the EPA’s 

MOBILE computer model 

• For nonroad sources, the EPA’s 

NONROAD computer model 

• Emissions inventories from previous 

years, if states do not submit current 

data 

To concentrate on only records 

pertaining to the oil and natural gas 

industry sector, data were extracted 

using two criteria. First, we specified 

that all facilities containing codes 

identifying the Oil and Natural Gas 

Production and the Natural Gas 

Transmission and Storage MACT source 

categories (MACT codes 0501 and 0504, 

respectively). Second, we extracted 

facilities identified with the following 

NAICS codes: 211 * * * (Oil and Gas 

Extraction), 221210 (Natural Gas 

Distribution), 4861 * * * (Pipeline 

Transportation of Crude Oil), and 4862 

* * * (Pipeline Transportation of 

Natural Gas). Once the data were 

extracted, we reviewed the Source 

Classification Codes (SCC) to assess 

whether there were any records 

included in the dataset that were clearly 

not a part of the oil and natural gas 

sector. Our review of the SCC also 

included assigning each SCC to an 

‘‘Emission Process Group’’ that 

represents emission point types within 

the oil and natural gas sector. 

Since these MACT standards only 

apply to major sources, only facilities 

designated as major sources in the NEI 

were extracted. In the NEI, sources are 

identified as major if the facility-wide 

emissions are greater than 10 tpy for any 

single HAP or 25 tpy for any 

combination of HAP. We believe that 

this may overestimate the number of 

major sources in the oil and natural gas 

sector because it does not take into 

account the limitations set forth in the 

CAA regarding aggregation of emissions 

from wells and associated equipment in 

determining major source status. 

The final dataset contained a total of 

1,311 major sources in the oil and 

natural gas sector; 990 in Oil and 

Natural Gas Production, and 321 in 

Natural Gas Transmission and Storage. 

To assess how representative this 

number of facilities was, we obtained 

information on the number of subject 

facilities for both MACT standards from 

the Enforcement and Compliance 

History Online (ECHO) database. The 

ECHO database is a web-based tool 

(http://www.epa-echo.gov/echo/ 

index.html) that provides public access 

to compliance and enforcement 

information for approximately 800,000 

EPA-regulated facilities. The ECHO 

database allows users to find permit, 

inspection, violation, enforcement 

action and penalty information covering 

the past 3 years. The site includes 

facilities regulated as CAA stationary 

sources, as well as Clean Water Act 

direct dischargers, and Resource 

Conservation and Recovery Act 

hazardous waste generators/handlers. 

The data in the ECHO database are 

updated monthly. 

We performed a query on the ECHO 

database requesting records for major 

sources, with NAICS codes 211*, 

221210, 4861* and 4862*, with 

information for MACT. The ECHO 

database query identified records for a 

total of 555 facilities, 269 in the Oil and 

Natural Gas Production source category 

(NAICS 211* and 221210) and 286 in 

the Natural Gas Transmission and 

Storage source category (NAICS 4861* 

and 4862*). This comparison leads us to 

conclude that, for the Natural Gas 

Transmission and Storage segment, the 

NEI database is representative of the 

number of sources subject to the rule. 

For the Oil and Natural Gas Production 

source category, it confirms our 

assumption that the NEI dataset 

contains more facilities than are subject 

to the rule. However, this provides a 

conservative overestimate of the number 

of sources, which we believe is 

appropriate for our risk analyses. 

We are requesting that the public 

provide a detailed review of the 

information in this dataset and provide 

comments and updated information 

where appropriate. Section X of this 

preamble provides an explanation of 

how to provide updated information for 

these datasets. 

B. What are the proposed decisions 

regarding certain unregulated emissions 

sources? 

In addition to actions relative to the 

technology review and risk reviews 

discussed below, we are proposing, 

pursuant to CAA sections 112(d)(2) and 

(3), MACT standards for glycol 

dehydrators and storage vessels for 

which standards were not previously 

developed. We are also proposing 

changes that affect the definition of 

‘‘associated equipment’’ which could 

apply these MACT standards to 

previously unregulated sources. 

1. Glycol Dehydrators 

Once natural gas has been separated 

from any liquid materials or products 

(e.g., crude oil, condensate or produced 

water), residual entrained water is 

removed from the natural gas by 

dehydration. Dehydration is necessary 

because water vapor may form hydrates, 

which are ice-like structures, and can 

cause corrosion in or plug equipment 

lines. The most widely used natural gas 

dehydration processes are glycol 

dehydration and solid desiccant 

dehydration. Solid desiccant 

dehydration, which is typically only 

used for lower throughputs, uses 

adsorption to remove water and is not 

a source of HAP emissions. 


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Glycol dehydration is an absorption 

process in which a liquid absorbent, 

glycol, directly contacts the natural gas 

stream and absorbs any entrained water 

vapor in a contact tower or absorption 

column. The majority of glycol 

dehydration units use triethylene glycol 

as the absorbent, but ethylene glycol 

and diethylene glycol are also used. The 

rich glycol, which has absorbed water 

vapor from the natural gas stream, 

leaves the bottom of the absorption 

column and is directed either to (1) a 

gas condensate glycol (GCG) separator 

(flash tank) and then a reboiler or (2) 

directly to a reboiler where the water is 

boiled off of the rich glycol. The 

regenerated glycol (lean glycol) is 

circulated, by pump, into the absorption 

tower. The vapor generated in the 

reboiler is directed to the reboiler vent. 

The reboiler vent is a source of HAP 

emissions. In the glycol contact tower, 

glycol not only absorbs water, but also 

absorbs selected hydrocarbons, 

including BTEX and n-hexane. The 

hydrocarbons are boiled off along with 

the water in the reboiler and vented to 

the atmosphere or to a control device. 

The most commonly used control 

device is a condenser. Condensers not 

only reduce emissions, but also recover 

condensable hydrocarbon vapors that 

can be recovered and sold. In addition, 

the dry non-condensable off-gas from 

the condenser may be used as fuel or 

recycled into the production process or 

directed to a flare, incinerator or other 

combustion device. 

If present, the GCG separator (flash 

tank) is also a potential source of HAP 

emissions. Some glycol dehydration 

units use flash tanks prior to the reboiler 

to separate entrained gases, primarily 

methane and ethane from the glycol. 

The flash tank off-gases are typically 

recovered as fuel or recycled to the 

natural gas production header. 

However, the flash tank may also be 

vented directly to the atmosphere. Flash 

tanks typically enhance the reboiler 

condenser’s emission reduction 

efficiency by reducing the concentration 

of non-condensable gases present in the 

stream prior to being introduced into 

the condenser. 

In the development of the MACT 

standards for the two oil and natural gas 

source categories, the EPA created two 

subcategories of glycol dehydrators 

based on actual annual average natural 

gas flowrate and actual average benzene 

emissions. Under 40 CFR part 63, 

subpart HH, (the Oil and Natural Gas 

Production NESHAP), the EPA 

established MACT standards for glycol 

dehydration units with an actual annual 

average natural gas flowrate greater than 

or equal to 85,000 scmd and actual 

average benzene emissions greater than 

or equal to 0.90 Mg/yr (40 CFR 

63.765(a)). The EPA did not establish 

standards for the other subcategory, 

which consists of glycol dehydration 

units that are below the flowrate and 

emission thresholds specified in subpart 

HH. Similarly, under 40 CFR part 63, 

subpart HHH (the Natural Gas 

Transmission and Storage NESHAP), the 

EPA established MACT standards for 

the subcategory of glycol dehydration 

units with an actual annual average 

natural gas flowrate greater than or 

equal to 283,000 scmd and actual 

average benzene emissions greater than 

or equal to 0.90 Mg/yr, but did not 

establish standards for the other 

subcategory, which consists of glycol 

dehydration units that are below the 

flowrate and emission thresholds 

specified in subpart HHH. As 

mentioned above, we refer to these 

unregulated dehydration units in both 

subparts HH and HHH as ‘‘small 

dehydrators’’ in this proposed rule. 

The EPA is proposing emission 

standards for these subcategories of 

small dehydrators (i.e., those 

dehydrators with an actual annual 

average natural gas flowrate less than 

85,000 scmd at production sites or 

283,000 scmd at natural gas 

transmission and storage sites, or actual 

average benzene emissions less than 0.9 

Mg/yr). Because we do not have any 

new emissions data concerning these 

emission points, we evaluated the 

dataset collected from industry during 

the development of the original MACT 

standards (legacy docket A–94–04, item 

II–B–01, disk 1 for oil and natural gas 

production facilities; and items IV–G– 

24, 26, 27, 30 and 31 for natural gas 

transmission and storage facilities). We 

believe this dataset is representative of 

currently operating glycol dehydrators 

because it contains information for a 

varied group of sources (i.e., units 

owned by different companies, located 

in different states, representing a range 

of gas compositions and emission 

controls) and that the processes have 

not changed significantly since the data 

were collected. 

In the Oil and Natural Gas Production 

source category, there were 91 glycol 

dehydration units with throughput and 

emissions data identified that would be 

classified as small glycol dehydration 

units. We evaluated the possibility of 

establishing a MACT floor as a Mg/yr 

limit. However, due to variability of gas 

throughput and inlet gas composition, 

we could not properly identify the best 

performing units by only considering 

emissions. To allow us to normalize the 

emissions for a more accurate 

determination of the best performing 

sources, we created an emission factor 

in terms of grams BTEX/scm-ppmv for 

each facility. The emission factor 

reflects the facility’s emission level, 

taking into consideration its natural gas 

throughput and inlet natural gas BTEX 

concentration. To determine the MACT 

floor for the existing dehydrators, we 

ranked each unit from lowest to highest, 

based on their emission factor, to 

determine the facilities in the top 12 

percent of the dataset. The MACT floor 

was an emission factor of 1.10 × 10¥4

grams BTEX/scm-ppmv. To meet this 

level of emissions, we anticipate that 

sources will use a variety of options, 

including, but not limited to, routing 

emissions to a condenser or to a 

combustion device. 

We also considered beyond-the-floor 

options for the existing sources, as 

required by section 112(d)(2) of the 

CAA. To achieve further reductions 

beyond the MACT floor level of control, 

sources would have to install an 

additional add-on control device, most 

likely a combustion device. Assuming 

the MACT floor control device is a 

combustion device, which generally 

achieves at least a 95-percent HAP 

reduction, then less than 5 percent of 

the initial HAP emissions remain. 

Installing a second device would 

involve the same costs as the first 

control, but would only achieve 1⁄20 of 

the reduction (i.e., reducing the 

remaining 5 percent by another 95 

percent represents a 4.49-percent 

reduction of the initial, uncontrolled 

emissions, which is 1⁄20 of the 95- 

percent reduction achieved with the 

first control). Based on the $8,360/Mg 

cost effectiveness of the floor level of 

control, we estimate that the 

incremental cost effectiveness of the 

second control to be $167,200/Mg. We 

do not believe this cost to be reasonable 

given the level of emission reduction. 

We are, therefore, proposing an 

emission standard for existing small 

dehydrators that reflects the MACT 

floor. 

For new small glycol dehydrators in 

the Oil and Natural Gas Production 

source category, based on our 

performance ranking, the best 

performing source has an emission 

factor of 4.66 × 10¥6 grams BTEX/scmppmv. To meet this level of emissions, 

we anticipate that sources will use a 

variety of options, including, but not 

limited to, routing emissions to a 

condenser or to a combustion device. 

The consideration of beyond-the-floor 

options for new small dehydrators 

would be the same as for existing small 

dehydrators, and, as stated above, we do 

not believe a cost of $167,200/Mg to be 

reasonable given the level of emission 


emcdonald on DSK2BSOYB1PROD with PROPOSALS2
Federal Register / Vol. 76, No. 163 / Tuesday, August 23, 2011 / Proposed Rules 52769 

reduction. We are, therefore, proposing 

a MACT standard for new small 

dehydrators that reflects the MACT floor 

level of control. 

Under our proposal, a small 

dehydrator’s actual MACT emission 

limit would be determined by 

multiplying the MACT floor emission 

factor in g BTEX/scm-ppmv by its unitspecific incoming natural gas 

throughput and BTEX concentration for 

the dehydrator. A formula is provided 

in 40 CFR 63.765(b)(1)(iii) to calculate 

the MACT limit as an annual value. 

In the Natural Gas Transmission and 

Storage source category, there were 16 

facilities for which throughput and 

emissions data were available that 

would be classified as small glycol 

dehydration units. Since the number of 

units was less than 30, the MACT floor 

for existing sources was based on the 

top five performing units. Using the 

same emission factor concept, we 

determined that the MACT floor for 

existing sources is an emission factor 

equal to 6.42 × 10¥5 grams BTEX/scmppmv. To meet this level of emissions, 

we anticipate that sources will use a 

variety of options, including, but not 

limited to, routing emissions to a 

condenser or to a combustion device. 

We also considered beyond-the-floor 

options for the existing small 

dehydrators as required by section 

112(d)(2) of the CAA. To achieve further 

reductions beyond the MACT floor level 

of control, sources would have to install 

an additional add-on control device, 

most likely a combustion device. 

Assuming the MACT floor control 

device is a combustion device, which 

generally achieves at least a 95-percent 

HAP reduction, then less than 5 percent 

of the initial HAP emissions remain. 

Installing a second device would 

involve the same costs as the first 

control device, but would only achieve 

1⁄20 of the reduction (i.e., reducing the 

remaining 5 percent by another 95 

percent represents a 4.49-percent 

reduction of the initial, uncontrolled 

emissions, which is 1⁄20 of the 95- 

percent reduction achieved with the 

first control). Based on the $1,650/Mg 

cost effectiveness of the floor level of 

control, we estimate that the 

incremental cost effectiveness of the 

second control to be $33,000/Mg. We do 

not believe this cost to be reasonable 

given the level of emission reduction. 

We are, therefore, proposing an 

emission standard for existing small 

dehydrators that reflects the MACT 

floor. 

For new small glycol dehydrators, 

based on our performance ranking, the 

best performing source has an emission 

factor of 1.10 × 10¥5 grams BTEX/scmppmv. To meet this level of emissions, 

we anticipate that sources will use a 

variety of options, including, but not 

limited to, routing emissions to a 

condenser or to a combustion device. 

The consideration of beyond-the-floor 

options for new small dehydrators 

would be the same as for existing small 

dehydrators, and, as stated above, we do 

not believe a cost of $33,000/Mg to be 

reasonable given the level of emission 

reduction. We are, therefore, proposing 

an emission standard for new sources 

that reflects the MACT floor level of 

control. 

Under our proposal, a source’s actual 

MACT emissions limit would be 

determined by multiplying this 

emission factor by their unit-specific 

incoming natural gas throughput and 

BTEX concentration for the dehydrator. 

A formula is provided in 40 CFR 

63.1275(b)(1)(iii) to calculate the limit 

as an annual value. 

As discussed below, we are proposing 

that, with the removal of the 1-ton 

alternative compliance option from the 

existing standards for glycol 

dehydrators, the MACT for these two 

source categories would provide an 

ample margin of safety to protect public 

health. We, therefore, maintain that, 

after the implementation of the small 

dehydrator standards discussed above, 

these MACT will continue to provide an 

ample margin of safety to protect public 

health. Consequently, we do not believe 

it will be necessary to conduct another 

residual risk review under CAA section 

112(f) for these two source categories 8 

years following promulgation of the 

small dehydrator standards merely due 

to the addition of these new MACT 

requirements. 

2. Storage Vessels 

Crude oil, condensate and produced 

water are typically stored in fixed-roof 

storage vessels. Some vessels used for 

storing produced water may be open-top 

tanks. These vessels, which are operated 

at or near atmospheric pressure 

conditions, are typically located at tank 

batteries. A tank battery refers to the 

collection of process components used 

to separate, treat and store crude oil, 

condensate, natural gas and produced 

water. The extracted products from 

productions wells enter the tank battery 

through the production header, which 

may collect product from many wells. 

Emissions from storage vessels are a 

result of working, breathing and flash 

losses. Working losses occur due to the 

emptying and filling of storage tanks. 

Breathing losses are the release of gas 

associated with daily temperature 

fluctuations and other equilibrium 

effects. Flash losses occur when a liquid 

with entrained gases is transferred from 

a vessel with higher pressure to a vessel 

with lower pressure, thus, allowing 

entrained gases or a portion of the liquid 

to vaporize or flash. In the oil and 

natural gas production segment, flashing 

losses occur when live crude oils or 

condensates flow into a storage tank 

from a processing vessel operated at a 

higher pressure. Typically, the larger the 

pressure drop, the more flashing 

emission will occur in the storage stage. 

Temperature of the liquid may also 

influence the amount of flash emissions. 

In the Oil and Natural Gas Production 

NESHAP (40 CFR part 63, subpart HH), 

the MACT standards for storage vessels 

apply only to those with the PFE. 

Storage vessels with the PFE are defined 

as storage vessels that contain 

hydrocarbon liquids that meet the 

following criteria: 

• A stock tank gas to oil ratio (GOR) 

greater than or equal to 0.31 cubic 

meters per liter (m3/liter); and 

• An American Petroleum Institute 

(API) gravity greater than or equal to 40 

degrees; and 

• An actual annual average 

hydrocarbon liquid throughput greater 

than or equal to 79,500 liters per day 

(liter/day). 

Accordingly, there is no emission 

limit in the existing MACT for storage 

vessels without the PFE. However, the 

MACT analysis performed at the time 

indicates that the MACT floor was based 

on all storage vessels, not just those 

vessels with flash emissions. See, 

Recommendation of MACT Floor Levels 

for HAP Emission Points at Major 

Sources in the Oil and Natural Gas 

Production Source Category, (September 

23, 1997, Docket A–94–04, Item II–A– 

07). We, therefore, propose to apply the 

existing MACT for storage vessels with 

PFE to all storage vessels (i.e., storage 

vessels with the PFE, as well as those 

without the PFE). 

3. Definition of Associated Equipment 

CAA section 112(n)(4)(A) provides: 

Notwithstanding the provisions of 

subsection (a), emissions from any oil or gas 

exploration or production well (with its 

associated equipment) and emission from 

any pipeline compressor or pump station 

shall not be aggregated with emissions from 

other similar units, whether or not such units 

are in contiguous area or under common 

control, to determine whether such units or 

stations are major sources. 

As stated above, the CAA prevents 

aggregation of HAP emissions from 

wells and associated equipment in 

making major source determinations. In 

the absence of clear guidance in the 

statute on what constitutes ‘‘associated 

equipment,’’ the EPA sought to define 


emcdonald on DSK2BSOYB1PROD with PROPOSALS2
52770 Federal Register / Vol. 76, No. 163 / Tuesday, August 23, 2011 / Proposed Rules 

14U.S. EPA SAB. Risk and Technology Review 

(RTR) Risk Assessment Methodologies: For Review 

by the EPA’s Science Advisory Board with Case 

Studies—MACT I Petroleum Refining Sources and 

Portland Cement Manufacturing, May 2010. 

15U.S. EPA. Revision to the Guideline on Air 

Quality Models: Adoption of a Preferred General 

Purpose (Flat and Complex Terrain) Dispersion 

Model and Other Revisions (70 FR 68218, 

November 9, 2005). 

‘‘associated equipment’’ in a way that 

recognizes the need to implement relief 

for this industry as Congress intended 

and that also allow for the appropriate 

regulation of significant emission 

points. 64 FR at 32619. Accordingly, in 

the existing Oil and Natural Gas 

Production NESHAP (1998 and 1999 

NESHAP), the EPA defined ‘‘associated 

equipment’’ to exclude glycol 

dehydration units and storage vessels 

with PFE (thus allowing their emissions 

to be included in determining major 

source status) because EPA identified 

these sources as substantial contributors 

to HAP emissions. Id. EPA explained in 

that NESHAP that, because a single 

storage vessel with flash emissions may 

emit several Mg of HAP per year and 

individual glycol dehydrators may emit 

above the major source level, storage 

vessels with PFE and glycol dehydrators 

are large individual sources of HAP, 63 

FR 6288, 6301 (1998). The EPA 

therefore considered these emission 

sources substantial contributors to HAP 

emissions and excluded them from the 

definition of ‘‘associated equipment.’’ 

64 FR at 32619. We have recently 

examined HAP emissions from storage 

vessels without flash emissions and 

found that these emissions are 

significant and comparable to those 

vessels with flash emissions. For 

example, one storage vessel with an API 

gravity of 30 degrees and a GOR of 2.09 

× 10¥3 m3/liter with a throughput of 

79,500 liter/day had HAP emissions of 

9.91 Mg/yr, including 9.45 Mg/yr of nhexane. 

Because storage vessels without the 

PFE can have significant emissions at 

levels that are comparable to emissions 

from storage vessels with the PFE, there 

is no appreciable difference between 

storage vessels with the PFE and those 

without the PFE for purposes of 

defining ‘‘associated equipment.’’ We 

are, therefore, proposing to amend the 

associated equipment definition to 

exclude all storage vessels and not just 

storage vessels with the PFE. 

C. How did we perform the risk 

assessment and what are the results and 

proposed decisions? 

1. How did we estimate risks posed by 

the source categories? 

The EPA conducted risk assessments 

that provided estimates for each source 

in a category of the MIR posed by the 

HAP emissions, the HI for chronic 

exposures to HAP with the potential to 

cause noncancer health effects, and the 

hazard quotient (HQ) for acute 

exposures to HAP with the potential to 

cause noncancer health effects. The 

assessments also provided estimates of 

the distribution of cancer risks within 

the exposed populations, cancer 

incidence and an evaluation of the 

potential for adverse environmental 

effects for each source category. The risk 

assessments consisted of seven primary 

steps, as discussed below. The docket 

for this rulemaking contains the 

following document which provides 

more information on the risk assessment 

inputs and models: Draft Residual Risk 

Assessment for the Oil and Gas 

Production and Natural Gas 

Transmission and Storage Source 

Categories. The methods used to assess 

risks (as described in the seven primary 

steps below) are consistent with those 

peer-reviewed by a panel of the EPA’s 

Science Advisory Board (SAB) in 2009 

and described in their peer review 

report issued in 2010 14; they are also 

consistent with the key 

recommendations contained in that 

report. 

a. Establishing the Nature and 

Magnitude of Actual Emissions and 

Identifying the Emissions Release 

Characteristics 

As discussed in section VII.A of this 

preamble, we used a dataset based on 

the 2005 NEI as the basis for the risk 

assessment. In addition to the quality 

assurance (QA) of the facilities 

contained in the dataset, we also 

checked the coordinates of every facility 

in the dataset through visual 

observations using tools such as 

GoogleEarth and ArcView. Where 

coordinates were found to be incorrect, 

we identified and corrected them to the 

extent possible. We also performed QA 

of the emissions data and release 

characteristics to ensure there were no 

outliers. 

b. Establishing the Relationship 

Between Actual Emissions and MACTAllowable Emissions Levels 

The available emissions data in the 

MACT dataset represent the estimates of 

mass of emissions actually emitted 

during the specified annual time period. 

These ‘‘actual’’ emission levels are often 

lower than the emission levels that a 

facility might be allowed to emit and 

still comply with the MACT standards. 

The emissions level allowed to be 

emitted by the MACT standards is 

referred to as the ‘‘MACT-allowable’’ 

emissions level. This represents the 

highest emissions level that could be 

emitted by the facility without violating 

the MACT standards. 

We discussed the use of both MACTallowable and actual emissions in the 

final Coke Oven Batteries residual risk 

rule (70 FR 19998–19999, April 15, 

2005) and in the proposed and final 

Hazardous Organic NESHAP residual 

risk rules (71 FR 34428, June 14, 2006, 

and 71 FR 76609, December 21, 2006, 

respectively). In those previous actions, 

we noted that assessing the risks at the 

MACT-allowable level is inherently 

reasonable since these risks reflect the 

maximum level sources could emit and 

still comply with national emission 

standards. But we also explained that it 

is reasonable to consider actual 

emissions, where such data are 

available, in both steps of the risk 

analysis, in accordance with the 

Benzene NESHAP. (54 FR 38044, 

September 14, 1989.) 

To estimate emissions at the MACTallowable level, we developed a ratio of 

MACT-allowable to actual emissions for 

each emissions source type in each 

source category, based on the level of 

control required by the MACT standards 

compared to the level of reported actual 

emissions and available information on 

the level of control achieved by the 

emissions controls in use. 

c. Conducting Dispersion Modeling, 

Determining Inhalation Exposures and 

Estimating Individual and Population 

Inhalation Risks 

Both long-term and short-term 

inhalation exposure concentrations and 

health risks from each source in the 

source categories addressed in this 

proposal were estimated using the 

Human Exposure Model (HEM) 

(Community and Sector HEM–3 version 

1.1.0). The HEM–3 performs three 

primary risk assessment activities: 

(1) Conducting dispersion modeling to 

estimate the concentrations of HAP in 

ambient air, (2) estimating long-term 

and short-term inhalation exposures to 

individuals residing within 50 km of the 

modeled sources and (3) estimating 

individual and population-level 

inhalation risks using the exposure 

estimates and quantitative doseresponse information. 

The dispersion model used by HEM– 

3 is AERMOD, which is one of the 

EPA’s preferred models for assessing 

pollutant concentrations from industrial 

facilities.15 To perform the dispersion 

modeling and to develop the 

preliminary risk estimates, HEM–3 

draws on three data libraries. The first 

is a library of meteorological data, 


emcdonald on DSK2BSOYB1PROD with PROPOSALS2
Federal Register / Vol. 76, No. 163 / Tuesday, August 23, 2011 / Proposed Rules 52771 

16A census block is generally the smallest 

geographic area for which census statistics are 

tabulated. 

17For details on the justification for this decision, 

see the memorandum in the docket from Peter 

Preuss to Steve Page entitled, Recommendation for 

Formaldehyde Inhalation Cancer Risk Values, 

January 22, 2010. 

18U.S. EPA. Performing risk assessments that 

include carcinogens described in the Supplemental 

Guidance as having a mutagenic mode of action. 

Science Policy Council Cancer Guidelines 

Implementation Work Group Communication II: 

Memo from W.H. Farland, dated October 4, 2005. 

19See the Risk Assessment for Source Categories 

document available in the docket for a list of HAP 

with a mutagenic mode of action. 

20U.S. EPA. Supplemental Guidance for 

Assessing Early-Life Exposure to Carcinogens. EPA/ 

630/R–03/003F, 2005. http://www.epa.gov/ttn/atw/ 

childrens_supplement_final.pdf. 

21U.S. EPA. Science Policy Council Cancer 

Guidelines Implementation Workgroup 

Communication II: Memo from W.H. Farland, dated 

June 14, 2006. 

22These classifications also coincide with the 

terms ‘‘known carcinogen, probable carcinogen and 

possible carcinogen,’’ respectively, which are the 

terms advocated in the EPA’s previous Guidelines 

for Carcinogen Risk Assessment, published in 1986 

(51 FR 33992, September 24, 1986). Summing the 

risks of these individual compounds to obtain the 

cumulative cancer risks is an approach that was 

recommended by the EPA’s SAB in their 2002 peer 

review of EPA’s NATA entitled, NATA—Evaluating 

the National-scale Air Toxics Assessment 1996 

Data—an SAB Advisory, available at: http:// 

yosemite.epa.gov/sab/sabproduct.nsf/ 

214C6E915BB04E14852570CA007A682C/$File/ 

ecadv02001.pdf. 

which is used for dispersion 

calculations. This library includes 

1 year of hourly surface and upper air 

observations for more than 158 

meteorological stations, selected to 

provide coverage of the United States 

and Puerto Rico. A second library of 

United States Census Bureau census 

block 16 internal point locations and 

populations provides the basis of 

human exposure calculations (Census, 

2000). In addition, for each census 

block, the census library includes the 

elevation and controlling hill height, 

which are also used in dispersion 

calculations. A third library of pollutant 

unit risk factors and other health 

benchmarks is used to estimate health 

risks. These risk factors and health 

benchmarks are the latest values 

recommended by the EPA for HAP and 

other toxic air pollutants. These values 

are available at http://www.epa.gov/ttn/ 

atw/toxsource/summary.html and are 

discussed in more detail later in this 

section. 

In developing the risk assessment for 

chronic exposures, we used the 

estimated annual average ambient air 

concentration of each of the HAP 

emitted by each source for which we 

have emissions data in the source 

category. The air concentrations at each 

nearby census block centroid were used 

as a surrogate for the chronic inhalation 

exposure concentration for all the 

people who reside in that census block. 

We calculated the MIR for each facility 

as the cancer risk associated with a 

continuous lifetime (24 hours per day, 

7 days per week, and 52 weeks per year 

for a 70-year period) exposure to the 

maximum concentration at the centroid 

of an inhabited census block. Individual 

cancer risks were calculated by 

multiplying the estimated lifetime 

exposure to the ambient concentration 

of each of the HAP (in micrograms per 

cubic meter) by its unit risk estimate 

(URE), which is an upper bound 

estimate of an individual’s probability 

of contracting cancer over a lifetime of 

exposure to a concentration of 1 

microgram of the pollutant per cubic 

meter of air. For residual risk 

assessments, we generally use URE 

values from the EPA’s Integrated Risk 

Information System (IRIS). For 

carcinogenic pollutants without the EPA 

IRIS values, we look to other reputable 

sources of cancer dose-response values, 

often using California EPA (CalEPA) 

URE values, where available. In cases 

where new, scientifically credible doseresponse values have been developed in 

a manner consistent with the EPA 

guidelines and have undergone a peer 

review process similar to that used by 

the EPA, we may use such doseresponse values in place of or in 

addition to other values, if appropriate. 

Formaldehyde is a unique case. In 

2004, the EPA determined that the 

Chemical Industry Institute of 

Toxicology (CIIT) cancer dose-response 

value for formaldehyde (5.5 × 10¥9 per 

μg/m3) was based on better science than 

the IRIS cancer dose-response value 

(1.3 × 10¥5 per μg/m3) and we switched 

from using the IRIS value to the CIIT 

value in risk assessments supporting 

regulatory actions. However, subsequent 

research published by the EPA suggests 

that the CIIT model was not appropriate 

and in 2010 the EPA returned to using 

the 1991 IRIS value, which is more 

health protective.17 The EPA has been 

working on revising the formaldehyde 

IRIS assessment and the National 

Academy of Sciences (NAS) completed 

its review of the EPA’s draft in May of 

2011. EPA is reviewing the public 

comments and the NAS independent 

scientific peer review, and the draft IRIS 

assessment will be revised and the final 

assessment will be posted on the IRIS 

database. In the interim, we will present 

findings using the 1991 IRIS value as a 

primary estimate, and may also consider 

other information as the science 

evolves. 

In the case of benzene, the high end 

of the reported cancer URE range was 

used in our assessments to provide a 

conservative estimate of potential 

cancer risks. Use of the high end of the 

range provides risk estimates that are 

approximately 3.5 times higher than use 

of the equally-plausible low end value. 

We also evaluated the impact of using 

the low end of the URE range on our 

risk results. 

We also note that polycyclic organic 

matter (POM), a carcinogenic HAP with 

a mutagenic mode of action, is emitted 

by some of the facilities in these two 

categories.18 For this compound 

group,19 the age-dependent adjustment 

factors (ADAF) described in the EPA’s 

Supplemental Guidance for Assessing 

Susceptibility from Early-Life Exposure 

to Carcinogens 20 were applied. This 

adjustment has the effect of increasing 

the estimated lifetime risks for POM by 

a factor of 1.6. In addition, although 

only a small fraction of the total POM 

emissions were not reported as 

individual compounds, the EPA 

expresses carcinogenic potency for 

compounds in this group in terms of 

benzo[a]pyrene equivalence, based on 

evidence that carcinogenic POM has the 

same mutagenic mechanism of action as 

benzo[a]pyrene. For this reason, the 

EPA’s Science Policy Council 21

recommends applying the Supplemental 

Guidance to all carcinogenic polycyclic 

aromatic hydrocarbons for which risk 

estimates are based on relative potency. 

Accordingly, we have applied the ADAF 

to the benzo[a]pyrene equivalent 

portion of all POM mixtures. 

Incremental individual lifetime 

cancer risks associated with emissions 

from the source category were estimated 

as the sum of the risks for each of the 

carcinogenic HAP (including those 

classified as carcinogenic to humans, 

likely to be carcinogenic to humans and 

suggestive evidence of carcinogenic 

potential 22) emitted by the modeled 

source. Cancer incidence and the 

distribution of individual cancer risks 

for the population within 50 km of any 

source were also estimated for the 

source category as part of these 

assessments by summing individual 

risks. A distance of 50 km is consistent 

with both the analysis supporting the 

1989 Benzene NESHAP (54 FR 38044) 

and the limitations of Gaussian 

dispersion models, including AERMOD. 

To assess risk of noncancer health 

effects from chronic exposures, we 

summed the HQ for each of the HAP 

that affects a common target organ 

system to obtain the HI for that target 

organ system (or target organ-specific 

HI, TOSHI). The HQ for chronic 

exposures is the estimated chronic 


emcdonald on DSK2BSOYB1PROD with PROPOSALS2
52772 Federal Register / Vol. 76, No. 163 / Tuesday, August 23, 2011 / Proposed Rules 

23NAS, 2001. Standing Operating Procedures for 

Developing Acute Exposure Levels for Hazardous 

Chemicals, page 2. 

24ERP Committee Procedures and 

Responsibilities. November 1, 2006. American 

Industrial Hygiene Association. 

exposure divided by the chronic 

reference level, which is either the EPA 

reference concentration (RfC), defined 

as ‘‘an estimate (with uncertainty 

spanning perhaps an order of 

magnitude) of a continuous inhalation 

exposure to the human population 

(including sensitive subgroups) that is 

likely to be without an appreciable risk 

of deleterious effects during a lifetime,’’ 

or, in cases where an RfC from the 

EPA’s IRIS database is not available, the 

EPA will utilize the following 

prioritized sources for our chronic doseresponse values: (1) The Agency for 

Toxic Substances and Disease Registry 

Minimum Risk Level, which is defined 

as ‘‘an estimate of daily human 

exposure to a substance that is likely to 

be without an appreciable risk of 

adverse effects (other than cancer) over 

a specified duration of exposure’’; (2) 

the CalEPA Chronic Reference Exposure 

Level (REL), which is defined as ‘‘the 

concentration level at or below which 

no adverse health effects are anticipated 

for a specified exposure duration’’; and 

(3), as noted above, in cases where 

scientifically credible dose-response 

values have been developed in a manner 

consistent with the EPA guidelines and 

have undergone a peer review process 

similar to that used by the EPA, we may 

use those dose-response values in place 

of or in concert with other values. 

Screening estimates of acute 

exposures and risks were also evaluated 

for each of the HAP at the point of 

highest off-site exposure for each facility 

(i.e., not just the census block 

centroids), assuming that a person is 

located at this spot at a time when both 

the peak (hourly) emission rate and 

worst-case dispersion conditions (1991 

calendar year data) occur. The acute HQ 

is the estimated acute exposure divided 

by the acute dose-response value. In 

each case, acute HQ values were 

calculated using best available, shortterm dose-response values. These acute 

dose-response values, which are 

described below, include the acute REL, 

acute exposure guideline levels (AEGL) 

and emergency response planning 

guidelines (ERPG) for 1-hour exposure 

durations. As discussed below, we used 

conservative assumptions for emission 

rates, meteorology and exposure 

location for our acute analysis. 

As described in the CalEPA’s Air 

Toxics Hot Spots Program Risk 

Assessment Guidelines, Part I, The 

Determination of Acute Reference 

Exposure Levels for Airborne Toxicants, 

an acute REL value (http:// 

www.oehha.ca.gov/air/pdf/acuterel.pdf) 

is defined as ‘‘the concentration level at 

or below which no adverse health 

effects are anticipated for a specified 

exposure duration.’’ Acute REL values 

are based on the most sensitive, 

relevant, adverse health effect reported 

in the medical and toxicological 

literature. Acute REL values are 

designed to protect the most sensitive 

individuals in the population by the 

inclusion of margins of safety. Since 

margins of safety are incorporated to 

address data gaps and uncertainties, 

exceeding the acute REL does not 

automatically indicate an adverse health 

impact. 

AEGL values were derived in 

response to recommendations from the 

National Research Council (NRC). As 

described in Standing Operating 

Procedures (SOP) of the National 

Advisory Committee on Acute Exposure 

Guideline Levels for Hazardous 

Substances (http://www.epa.gov/ 

opptintr/aegl/pubs/sop.pdf),23 ‘‘the 

NRC’s previous name for acute exposure 

levels—community emergency exposure 

levels—was replaced by the term AEGL 

to reflect the broad application of these 

values to planning, response, and 

prevention in the community, the 

workplace, transportation, the military, 

and the remediation of Superfund 

sites.’’ This document also states that 

AEGL values ‘‘represent threshold 

exposure limits for the general public 

and are applicable to emergency 

exposures ranging from 10 minutes to 

eight hours.’’ The document lays out the 

purpose and objectives of AEGL by 

stating (page 21) that ‘‘the primary 

purpose of the AEGL program and the 

National Advisory Committee for Acute 

Exposure Guideline Levels for 

Hazardous Substances is to develop 

guideline levels for once-in-a-lifetime, 

short-term exposures to airborne 

concentrations of acutely toxic, highpriority chemicals.’’ In detailing the 

intended application of AEGL values, 

the document states (page 31) that ‘‘[i]t 

is anticipated that the AEGL values will 

be used for regulatory and 

nonregulatory purposes by U.S. Federal 

and state agencies and possibly the 

international community in conjunction 

with chemical emergency response, 

planning, and prevention programs. 

More specifically, the AEGL values will 

be used for conducting various risk 

assessments to aid in the development 

of emergency preparedness and 

prevention plans, as well as real-time 

emergency response actions, for 

accidental chemical releases at fixed 

facilities and from transport carriers.’’ 

The AEGL–1 value is then specifically 

defined as ‘‘the airborne concentration 

of a substance above which it is 

predicted that the general population, 

including susceptible individuals, could 

experience notable discomfort, 

irritation, or certain asymptomatic 

nonsensory effects. However, the effects 

are not disabling and are transient and 

reversible upon cessation of exposure.’’ 

The document also notes (page 3) that, 

‘‘Airborne concentrations below AEGL– 

1 represent exposure levels that can 

produce mild and progressively 

increasing but transient and 

nondisabling odor, taste, and sensory 

irritation or certain asymptomatic, 

nonsensory effects.’’ Similarly, the 

document defines AEGL–2 values as 

‘‘the airborne concentration (expressed 

as ppm or mg/m3) of a substance above 

which it is predicted that the general 

population, including susceptible 

individuals, could experience 

irreversible or other serious, long-lasting 

adverse health effects or an impaired 

ability to escape.’’ 

ERPG values are derived for use in 

emergency response, as described in the 

American Industrial Hygiene 

Association’s document entitled, 

Emergency Response Planning 

Guidelines (ERPG) Procedures and 

Responsibilities (http://www.aiha.org/ 

1documents/committees/ 

ERPSOPs2006.pdf) which states that, 

‘‘Emergency Response Planning 

Guidelines were developed for 

emergency planning and are intended as 

health based guideline concentrations 

for single exposures to chemicals.’’ 24

The ERPG–1 value is defined as ‘‘the 

maximum airborne concentration below 

which it is believed that nearly all 

individuals could be exposed for up to 

1 hour without experiencing other than 

mild transient adverse health effects or 

without perceiving a clearly defined, 

objectionable odor.’’ Similarly, the 

ERPG–2 value is defined as ‘‘the 

maximum airborne concentration below 

which it is believed that nearly all 

individuals could be exposed for up to 

1 hour without experiencing or 

developing irreversible or other serious 

health effects or symptoms which could 

impair an individual’s ability to take 

protective action.’’ 

As can be seen from the definitions 

above, the AEGL and ERPG values 

include the similarly-defined severity 

levels 1 and 2. For many chemicals, a 

severity level 1 value AEGL or ERPG has 

not been developed; in these instances, 

higher severity level AEGL–2 or ERPG– 

2 values are compared to our modeled 


emcdonald on DSK2BSOYB1PROD with PROPOSALS2
Federal Register / Vol. 76, No. 163 / Tuesday, August 23, 2011 / Proposed Rules 52773 

25See http://www.tceq.state.tx.us/compliance/

field_ops/eer/index.html or docket to access the 

source of these data. 

26The SAB peer review of RTR Risk Assessment 

Methodologies is available at: http://yosemite.epa.

gov/sab/sabproduct.nsf/4AB3966E263D943A852

5771F00668381/$File/EPA-SAB-10-007- 

unsigned.pdf. 

27 29 CFR 1910.1028, Benzene. Available online 

at http://www.osha.gov/pls/oshaweb/owadisp.

show_document?p_table=STANDARDS&p_

id=10042. 

28ACGIH (2001) Benzene. In Documentation of 

the TLVs® and BEIs® with Other Worldwide 

Occupational Exposure Values. ACGIH, 1300 

Kemper Meadow Drive, Cincinnati, OH 45240 

(ISBN: 978–1–882417–74–2) and available online at 

http://www.acgih.org. 

29The ACGIH definition of a TLV–STEL states 

that ‘‘Exposures above the TLV–TWA up to the 

TLV–STEL should be less than 15 minutes, should 

occur no more than four times per day, and there 

should be at least 60 minutes between successive 

exposures in this range.’’ 

30NIOSH. Occupational Safety and Health 

Guideline for Benzene; http://www.cdc.gov/niosh/ 

74-137.html. 

exposure levels to screen for potential 

acute concerns. 

Acute REL values for 1-hour exposure 

durations are typically lower than their 

corresponding AEGL–1 and ERPG–1 

values. Even though their definitions are 

slightly different, AEGL–1 values are 

often the same as the corresponding 

ERPG–1 values, and AEGL–2 values are 

often equal to ERPG–2 values. 

Maximum HQ values from our acute 

screening risk assessments typically 

result when basing them on the acute 

REL value for a particular pollutant. In 

cases where our maximum acute HQ 

value exceeds 1, we also report the HQ 

value based on the next highest acute 

dose-response value (usually the AEGL– 

1 and/or the ERPG–1 value). 

To develop screening estimates of 

acute exposures, we developed 

estimates of maximum hourly emission 

rates by multiplying the average actual 

annual hourly emission rates by a factor 

to cover routinely variable emissions. 

We chose the factor based on process 

knowledge and engineering judgment 

and with awareness of a Texas study of 

short-term emissions variability, which 

showed that most peak emission events, 

in a heavily-industrialized 4-county area 

(Harris, Galveston, Chambers and 

Brazoria Counties, Texas) were less than 

twice the annual average hourly 

emission rate. The highest peak 

emission event was 74 times the annual 

average hourly emission rate, and the 

99th percentile ratio of peak hourly 

emission rate to the annual average 

hourly emission rate was 9.25 This 

analysis is provided in Appendix 4 of 

the Draft Residual Risk Assessment for 

the Oil and Gas Production and Natural 

Gas Transmission and Storage Source 

Categories, which is available in the 

docket for this action. Considering this 

analysis, unless specific process 

knowledge or data are available to 

provide an alternate value, to account 

for more than 99 percent of the peak 

hourly emissions, we apply a 

conservative screening multiplication 

factor of 10 to the average annual hourly 

emission rate in these acute exposure 

screening assessments. The factor of 10 

was used for both the Oil and Natural 

Gas Production and the Natural Gas 

Transmission and Storage source 

categories. 

In cases where acute HQ values from 

the screening step were less than or 

equal to 1, acute impacts were deemed 

negligible and no further analysis was 

performed. In cases where an acute HQ 

from the screening step was greater than 

1, additional site-specific data were 

considered to develop a more refined 

estimate of the potential for acute 

impacts of concern. The data 

refinements employed for these source 

categories consisted of using the sitespecific facility layout to distinguish 

facility property from an area where the 

public could be exposed. These 

refinements are discussed in the draft 

risk assessment document, which is 

available in the docket for each of these 

source categories. Ideally, we would 

prefer to have continuous measurements 

over time to see how the emissions vary 

by each hour over an entire year. Having 

a frequency distribution of hourly 

emission rates over a year would allow 

us to perform a probabilistic analysis to 

estimate potential threshold 

exceedances and their frequency of 

occurrence. Such an evaluation could 

include a more complete statistical 

treatment of the key parameters and 

elements adopted in this screening 

analysis. However, we recognize that 

having this level of data is rare, hence 

our use of the multiplier approach. 

To better characterize the potential 

health risks associated with estimated 

acute exposures to HAP, and in 

response to a key recommendation from 

the SAB’s peer review of the EPA’s RTR 

risk assessment methodologies,26 we 

generally examine a wider range of 

available acute health metrics than we 

do for our chronic risk assessments. 

This is in response to the SAB’s 

acknowledgement that there are 

generally more data gaps and 

inconsistencies in acute reference 

values than there are in chronic 

reference values. Comparisons of the 

estimated maximum off-site 1-hour 

exposure levels are not typically made 

to occupational levels for the purpose of 

characterizing public health risks in 

RTR assessments. This is because they 

are developed for working age adults 

and are not generally considered 

protective for the general public. We 

note that occupational ceiling values 

are, for most chemicals, set at levels 

higher than a 1-hour AEGL–1. 

As discussed in section VII.C.2 of this 

preamble, the maximum estimated 

worst-case 1-hour exposure to benzene 

outside the facility fence line for a 

facility in either source category is 12 

mg/m3. This estimated exposure 

exceeds the 6-hour REL by a factor of 9 

(HQREL = 9), but is significantly below 

the 1-hour AEGL–1 (HQAEGL–1 = 0.07). 

Although this worst-case exposure 

estimate does not exceed the AEGL–1, 

we note here that it slightly exceeds 

workplace ceiling level guidelines 

designed to protect the worker 

population for short duration (<15 

minute) increases in exposure to 

benzene, as discussed below. The 

occupational short-term exposure limit 

(STEL) standard for benzene developed 

by the Occupational Safety and Health 

Administration is 16 mg/m3, ‘‘as 

averaged over any 15-minute period.’’ 27

Occupational guideline STEL for 

exposures to benzene have also been 

developed by the American Conference 

of Governmental Industrial Hygienists 

(ACGIH) 28 for less than 15 minutes 29

(ACGIH threshold limit value (TLV)- 

STEL value of 8.0 mg/m3), and by the 

National Institute for Occupational 

Safety and Health (NIOSH) 30 ‘‘for any 

15 minute period in a work day’’ 

(NIOSH REL–STEL of 3.2 mg/m3). These 

shorter duration occupational values 

indicate potential concerns regarding 

health effects at exposure levels below 

the 1-hour AEGL–1 value. We solicit 

comment on the use of the occupational 

values described above in the 

interpretation of these worst-case acute 

screening exposure estimates. 

d. Conducting Multi-Pathway Exposure 

and Risk Modeling 

The potential for significant human 

health risks due to exposures via routes 

other than inhalation (i.e., multipathway exposures) and the potential 

for adverse environmental impacts were 

evaluated in a three-step process. In the 

first step, we determined whether any 

facilities emitted any HAP known to be 

PB–HAP (HAP known to be persistent 

and bio-accumulative) in the 

environment. There are 14 PB–HAP 

compounds or compound classes 

identified for this screening in the EPA’s 

Air Toxics Risk Assessment Library 

(available at http://www.epa.gov/ttn/ 

fera/risk_atra_vol1.html). They are 

cadmium compounds, chlordane, 

chlorinated dibenzodioxins and furans, 


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52774 Federal Register / Vol. 76, No. 163 / Tuesday, August 23, 2011 / Proposed Rules 

dichlorodiphenyldichloroethylene, 

heptachlor, hexachlorobenzene, 

hexachlorocyclohexane, lead 

compounds, mercury compounds, 

methoxychlor, polychlorinated 

biphenyls, POM, toxaphene and 

trifluralin. 

Since one or more of these PB–HAP 

are emitted by at least one facility in 

both source categories, we proceeded to 

the second step of the evaluation. In this 

step, we determined whether the 

facility-specific emission rates of each of 

the emitted PB–HAP were large enough 

to create the potential for significant 

non-inhalation human or environmental 

risks under reasonable worst-case 

conditions. To facilitate this step, we 

have developed emission rate 

thresholds for each PB–HAP using a 

hypothetical worst-case screening 

exposure scenario developed for use in 

conjunction with the EPA’s TRIM.FaTE 

model. The hypothetical screening 

scenario was subjected to a sensitivity 

analysis to ensure that its key design 

parameters were established such that 

environmental media concentrations 

were not underestimated (i.e., to 

minimize the occurrence of false 

negatives or results that suggest that 

risks might be acceptable when, in fact, 

actual risks are high) and to also 

minimize the occurrence of false 

positives for human health endpoints. 

We call this application of the 

TRIM.FaTE model TRIM–Screen. The 

facility-specific emission rates of each of 

the PB–HAP in each source category 

were compared to the TRIM–Screen 

emission threshold values for each of 

the PB–HAP identified in the source 

category datasets to assess the potential 

for significant human health risks or 

environmental risks via non-inhalation 

pathways. 

There was only one facility in the 

Natural Gas Transmission and Storage 

source category with reported emissions 

of PB–HAP, and the emission rates were 

less than the emission threshold values. 

There were 29 facilities in the Oil and 

Natural Gas Production source category 

with reported emissions of PB–HAP, 

and one of these had emission rates 

greater than the emission threshold 

values. In this case, the emission 

threshold value for POM was exceeded 

by a factor of 6. For POM, dairy, 

vegetables and fruits were the three 

most dominant exposure pathways 

driving human exposures in the 

hypothetical screening exposure 

scenario. The single facility with 

emissions exceeding the emission 

threshold value for POM is located in a 

highly industrialized area. Therefore, 

since the exposure pathways which 

would drive high human exposure are 

not locally available, multi-pathway 

exposures and environmental risks were 

deemed negligible, and no further 

analysis was performed. For further 

information on the multi-pathway 

analysis approach, see the residual risk 

documentation. 

e. Assessing Risks Considering 

Emissions Control Options 

In addition to assessing baseline 

inhalation risks and screening for 

potential multi-pathway risks, where 

appropriate, we also estimated risks 

considering the potential emission 

reductions that would be achieved by 

the particular control options under 

consideration. In these cases, the 

expected emissions reductions were 

applied to the specific HAP and 

emissions sources in the source category 

dataset to develop corresponding 

estimates of risk reductions. 

f. Conducting Other Risk-Related 

Analyses: Facility-Wide Assessments 

To put the source category risks in 

context, we also examined the risks 

from the entire ‘‘facility,’’ where the 

facility includes all HAP-emitting 

operations within a contiguous area and 

under common control. In other words, 

for each facility that includes one or 

more sources from one of the source 

categories under review, we examined 

the HAP emissions not only from the 

source category of interest, but also from 

all other emission sources at the facility. 

The emissions data for generating these 

‘‘facility-wide’’ risks were also obtained 

from the 2005 NEI. For every facility 

included in the MACT database, we also 

retrieved emissions data and release 

characteristics for all other emission 

sources at the same facility. We 

estimated the risks due to the inhalation 

of HAP that are emitted ‘‘facility-wide’’ 

for the populations residing within 50 

km of each facility, consistent with the 

methods used for the source category 

analysis described above. For these 

facility-wide risk analyses, the modeled 

source category risks were compared to 

the facility-wide risks to determine the 

portion of facility-wide risks that could 

be attributed to the source categories 

addressed in this proposal. We 

specifically examined the facilities 

associated with the highest estimates of 

risk and determined the percentage of 

that risk attributable to the source 

category of interest. The risk 

documentation available through the 

docket for this action provides the 

methodology and the results of the 

facility-wide analyses for each source 

category. 

g. Conducting Other Analyses: 

Demographic Analysis 

To examine the potential for any 

environmental justice (EJ) issues that 

might be associated with each source 

category, we performed a demographic 

analysis of population risk. In this 

analysis, we evaluated the distributions 

of HAP-related cancer and noncancer 

risks across different social, 

demographic and economic groups 

within the populations living near the 

facilities where these source categories 

are located. The development of 

demographic analyses to inform the 

consideration of EJ issues in the EPA 

rulemakings is an evolving science. The 

EPA offers the demographic analyses in 

this rulemaking to inform the 

consideration of potential EJ issues and 

invites public comment on the 

approaches used and the interpretations 

made from the results, with the hope 

that this will support the refinement 

and improve the utility of such analyses 

for future rulemakings. 

For the demographic analyses, we 

focus on the populations within 50 km 

of any facility estimated to have 

exposures to HAP which result in 

cancer risks of 1-in-1 million or greater, 

or noncancer HI of 1 or greater (based 

on the emissions of the source category 

or the facility, respectively). We 

examine the distributions of those risks 

across various demographic groups, 

comparing the percentages of particular 

demographic groups to the total number 

of people in those demographic groups 

nationwide. The results, including other 

risk metrics, such as average risks for 

the exposed populations, are 

documented in source-category-specific 

technical reports in the docket for both 

source categories covered in this 

proposal. 

The basis for the risk values used in 

these analyses were the modeling 

results based on actual emissions levels 

obtained from the HEM–3 model 

described above. The risk values for 

each census block were linked to a 

database of information from the 2000 

Decennial census that includes data on 

race and ethnicity, age distributions, 

poverty status, household incomes and 

education level. The Census Department 

Landview® database was the source of 

the data on race and ethnicity and the 

data on age distributions, poverty status, 

household incomes and education level 

were obtained from the 2000 Census of 

Population and Housing Summary File 

3 Long Form. While race and ethnicity 

census data are available at the census 

block level, the age and income census 

data are only available at the census 

block group level (which includes an 


emcdonald on DSK2BSOYB1PROD with PROPOSALS2
Federal Register / Vol. 76, No. 163 / Tuesday, August 23, 2011 / Proposed Rules 52775 

31Short-term mobility is movement from one 

micro-environment to another over the course of 

hours or days. Long-term mobility is movement 

from one residence to another over the course of a 

lifetime. 

average of 26 blocks or an average of 

1,350 people). Where census data are 

available at the block group level, but 

not the block level, we assumed that all 

census blocks within the block group 

have the same distribution of ages and 

incomes as the block group. 

For each source category, we focused 

on those census blocks where source 

category risk results show estimated 

lifetime inhalation cancer risks above 

1-in-1 million or chronic noncancer 

indices above 1 and determined the 

relative percentage of different racial 

and ethnic groups, different age groups, 

adults with and without a high school 

diploma, people living in households 

below the national median income and 

for people living below the poverty line 

within those census blocks. The specific 

census population categories studied 

include: 

• Total population 

• White 

• African American (or Black) 

• Native Americans 

• Other races and multiracial 

• Hispanic or Latino 

• Children 18 years of age and under 

• Adults 19 to 64 years of age 

• Adults 65 years of age and over 

• Adults without a high school diploma 

• Households earning under the 

national median income 

• People living below the poverty line 

It should be noted that these 

categories overlap in some instances, 

resulting in some populations being 

counted in more than one category (e.g., 

other races and multiracial and 

Hispanic). In addition, while not a 

specific census population category, we 

also examined risks to ‘‘Minorities,’’ a 

classification which is defined for these 

purposes as all race population 

categories except white. 

For further information about risks to 

the populations located near the 

facilities in these source categories, we 

also evaluated the estimated 

distribution of inhalation cancer and 

chronic noncancer risks associated with 

the HAP emissions from all the 

emissions sources at the facility (i.e., 

facility-wide). This analysis used the 

facility-wide RTR modeling results and 

the census data described above. 

The methodology and the results of 

the demographic analyses for each 

source category are included in a 

source-category-specific technical report 

for each of the categories, which are 

available in the docket for this action. 

h. Considering Uncertainties in Risk 

Assessment 

Uncertainty and the potential for bias 

are inherent in all risk assessments, 

including those performed for the 

source categories addressed in this 

proposal. Although uncertainty exists, 

we believe that our approach, which 

used conservative tools and 

assumptions, ensures that our decisions 

are health-protective. A brief discussion 

of the uncertainties in the emissions 

datasets, dispersion modeling, 

inhalation exposure estimates and doseresponse relationships follows below. A 

more thorough discussion of these 

uncertainties is included in the risk 

assessment documentation (referenced 

earlier) available in the docket for this 

action. 

i. Uncertainties in the Emissions 

Datasets 

Although the development of the 

MACT dataset involved QA/quality 

control processes, the accuracy of 

emissions values will vary depending 

on the source of the data, the degree to 

which data are incomplete or missing, 

the degree to which assumptions made 

to complete the datasets are inaccurate, 

errors in estimating emissions values 

and other factors. The emission 

estimates considered in this analysis 

generally are annual totals for certain 

years that do not reflect short-term 

fluctuations during the course of a year 

or variations from year to year. 

The estimates of peak hourly emission 

rates for the acute effects screening 

assessment were based on a 

multiplication factor of 10 applied to 

the average annual hourly emission rate, 

which is intended to account for 

emission fluctuations due to normal 

facility operations. Additionally, 

although we believe that we have data 

for most facilities in these two source 

categories in our RTR dataset, our 

dataset may not include data for all 

existing facilities. Moreover, there are 

uncertainties with regard to the 

identification of sources as major or area 

in the NEI for these source categories. 

ii. Uncertainties in Dispersion Modeling 

While the analysis employed the 

EPA’s recommended regulatory 

dispersion model, AERMOD, we 

recognize that there is uncertainty in 

ambient concentration estimates 

associated with any model, including 

AERMOD. In circumstances where we 

had to choose between various model 

options, where possible, model options 

(e.g., rural/urban, plume depletion, 

chemistry) were selected to provide an 

overestimate of ambient air 

concentrations of the HAP rather than 

underestimates. However, because of 

practicality and data limitation reasons, 

some factors (e.g., meteorology, building 

downwash) have the potential in some 

situations to overestimate or 

underestimate ambient impacts. For 

example, meteorological data were 

taken from a single year (1991) and 

facility locations can be a significant 

distance from the site where these data 

were taken. Despite these uncertainties, 

we believe that at off-site locations and 

census block centroids, the approach 

considered in the dispersion modeling 

analysis should generally yield 

overestimates of ambient HAP 

concentrations. 

iii. Uncertainties in Inhalation Exposure 

The effects of human mobility on 

exposures were not included in the 

assessment. Specifically, short-term 

mobility and long-term mobility 

between census blocks in the modeling 

domain were not considered.31 The 

assumption of not considering short or 

long-term population mobility does not 

bias the estimate of the theoretical MIR, 

nor does it affect the estimate of cancer 

incidence since the total population 

number remains the same. It does, 

however, affect the shape of the 

distribution of individual risks across 

the affected population, shifting it 

toward higher estimated individual 

risks at the upper end and reducing the 

number of people estimated to be at 

lower risks, thereby increasing the 

estimated number of people at specific 

risk levels. 

In addition, the assessment predicted 

the chronic exposures at the centroid of 

each populated census block as 

surrogates for the exposure 

concentrations for all people living in 

that block. Using the census block 

centroid to predict chronic exposures 

tends to over-predict exposures for 

people in the census block who live 

further from the facility, and underpredict exposures for people in the 

census block who live closer to the 

facility. Thus, using the census block 

centroid to predict chronic exposures 

may lead to a potential understatement 

or overstatement of the true maximum 

impact, but is an unbiased estimate of 

average risk and incidence. 

The assessments evaluate the cancer 

inhalation risks associated with 

continuous pollutant exposures over a 

70-year period, which is the assumed 

lifetime of an individual. In reality, both 

the length of time that modeled 

emissions sources at facilities actually 

operate (i.e., more or less than 70 years), 

and the domestic growth or decline of 

the modeled industry (i.e., the increase 


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32U.S. EPA. National-Scale Air Toxics 

Assessment for 1996. (EPA 453/R–01–003; January 

2001; page 85.) 

33 IRIS glossary (http://www.epa.gov/NCEA/iris/ 

help_gloss.htm). 

34An exception to this is the URE for benzene, 

which is considered to cover a range of values, each 

end of which is considered to be equally plausible 

and which is based on maximum likelihood 

estimates. 

35According to the NRC report, Science and 

Judgment in Risk Assessment (NRC, 1994) 

‘‘[Default] options are generic approaches, based on 

general scientific knowledge and policy judgment, 

that are applied to various elements of the risk 

assessment process when the correct scientific 

model is unknown or uncertain.’’ The 1983 NRC 

report, Risk Assessment in the Federal Government: 

Managing the Process, defined default option as 

‘‘the option chosen on the basis of risk assessment 

policy that appears to be the best choice in the 

absence of data to the contrary’’ (NRC, 1983a, p. 63). 

Therefore, default options are not rules that bind 

the Agency; rather, the Agency may depart from 

them in evaluating the risks posed by a specific 

substance when it believes this to be appropriate. 

In keeping with EPA’s goal of protecting public 

health and the environment, default assumptions 

are used to ensure that risk to chemicals is not 

underestimated (although defaults are not intended 

to overtly overestimate risk). See EPA, 2004, An 

Examination of EPA Risk Assessment Principles 

and Practices, EPA/100/B–04/001 available at: 

http://www.epa.gov/osa/pdfs/ratf-final.pdf. 

or decrease in the number or size of 

United States facilities), will influence 

the risks posed by a given source 

category. Depending on the 

characteristics of the industry, these 

factors will, in most cases, result in an 

overestimate both in individual risk 

levels and in the total estimated number 

of cancer cases. However, in rare cases, 

where a facility maintains or increases 

its emission levels beyond 70 years, 

residents live beyond 70 years at the 

same location, and the residents spend 

most of their days at that location, then 

the risks could potentially be 

underestimated. Annual cancer 

incidence estimates from exposures to 

emissions from these sources would not 

be affected by uncertainty in the length 

of time emissions sources operate. 

The exposure estimates used in these 

analyses assume chronic exposures to 

ambient levels of pollutants. Because 

most people spend the majority of their 

time indoors, actual exposures may not 

be as high, depending on the 

characteristics of the pollutants 

modeled. For many of the HAP, indoor 

levels are roughly equivalent to ambient 

levels, but for very reactive pollutants or 

larger particles, these levels are 

typically lower. This factor has the 

potential to result in an overstatement of 

25 to 30 percent of exposures.32

In addition to the uncertainties 

highlighted above, there are several 

factors specific to the acute exposure 

assessment that should be highlighted. 

The accuracy of an acute inhalation 

exposure assessment depends on the 

simultaneous occurrence of 

independent factors that may vary 

greatly, such as hourly emissions rates, 

meteorology, and human activity 

patterns. In this assessment, we assume 

that individuals remain for 1 hour at the 

point of maximum ambient 

concentration as determined by the cooccurrence of peak emissions and worstcase meteorological conditions. These 

assumptions would tend to overestimate 

actual exposures since it is unlikely that 

a person would be located at the point 

of maximum exposure during the time 

of worst-case impact. 

iv. Uncertainties in Dose-Response 

Relationships 

There are uncertainties inherent in 

the development of the dose-response 

values used in our risk assessments for 

cancer effects from chronic exposures 

and noncancer effects from both chronic 

and acute exposures. Some 

uncertainties may be considered 

quantitatively, and others generally are 

expressed in qualitative terms. We note 

as a preface to this discussion a point on 

dose-response uncertainty that is 

brought out in the EPA 2005 Cancer 

Guidelines; namely, that ‘‘the primary 

goal of the EPA actions is protection of 

human health; accordingly, as an 

Agency policy, risk assessment 

procedures, including default options 

that are used in the absence of scientific 

data to the contrary, should be health 

protective.’’ (EPA 2005 Cancer 

Guidelines, pages 1–7.) This is the 

approach followed here as summarized 

in the next several paragraphs. A 

complete detailed discussion of 

uncertainties and variability in doseresponse relationships is given in the 

residual risk documentation, which is 

available in the docket for this action. 

Cancer URE values used in our risk 

assessments are those that have been 

developed to generally provide an upper 

bound estimate of risk. That is, they 

represent a ‘‘plausible upper limit to the 

true value of a quantity’’ (although this 

is usually not a true statistical 

confidence limit).33 In some 

circumstances, the true risk could be as 

low as zero; however, in other 

circumstances, the risk could also be 

greater.34 When developing an upper 

bound estimate of risk and to provide 

risk values that do not underestimate 

risk, health-protective default 

approaches are generally used. To err on 

the side of ensuring adequate healthprotection, the EPA typically uses the 

upper bound estimates rather than 

lower bound or central tendency 

estimates in our risk assessments, an 

approach that may have limitations for 

other uses (e.g., priority-setting or 

expected benefits analysis). 

Chronic noncancer reference (RfC and 

reference dose (RfD)) values represent 

chronic exposure levels that are 

intended to be health-protective levels. 

Specifically, these values provide an 

estimate (with uncertainty spanning 

perhaps an order of magnitude) of daily 

oral exposure (RfD) or of a continuous 

inhalation exposure (RfC) to the human 

population (including sensitive 

subgroups) that is likely to be without 

an appreciable risk of deleterious effects 

during a lifetime. To derive values that 

are intended to be ‘‘without appreciable 

risk,’’ the methodology relies upon an 

uncertainty factor (UF) approach (U.S. 

EPA, 1993, 1994) which includes 

consideration of both uncertainty and 

variability. When there are gaps in the 

available information, UF are applied to 

derive reference values that are 

intended to protect against appreciable 

risk of deleterious effects. The UF are 

commonly default values,35 e.g., factors 

of 10 or 3, used in the absence of 

compound-specific data; where data are 

available, UF may also be developed 

using compound-specific information. 

When data are limited, more 

assumptions are needed and more UF 

are used. Thus, there may be a greater 

tendency to overestimate risk in the 

sense that further study might support 

development of reference values that are 

higher (i.e., less potent) because fewer 

default assumptions are needed. 

However, for some pollutants, it is 

possible that risks may be 

underestimated. While collectively 

termed ‘‘uncertainty factor,’’ these 

factors account for a number of different 

quantitative considerations when using 

observed animal (usually rodent) or 

human toxicity data in the development 

of the RfC. The UF are intended to 

account for: (1) Variation in 

susceptibility among the members of the 

human population (i.e., inter-individual 

variability); (2) uncertainty in 

extrapolating from experimental animal 

data to humans (i.e., interspecies 

differences); (3) uncertainty in 

extrapolating from data obtained in a 

study with less-than-lifetime exposure 

(i.e., extrapolating from sub-chronic to 

chronic exposure); (4) uncertainty in 

extrapolating the observed data to 

obtain an estimate of the exposure 

associated with no adverse effects; and 

(5) uncertainty when the database is 

incomplete or there are problems with 

the applicability of available studies. 

Many of the UF used to account for 

variability and uncertainty in the 

development of acute reference values 


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are quite similar to those developed for 

chronic durations, but they more often 

use individual UF values that may be 

less than 10. UF are applied based on 

chemical-specific or health effectspecific information (e.g., simple 

irritation effects do not vary appreciably 

between human individuals, hence a 

value of 3 is typically used), or based on 

the purpose for the reference value (see 

the following paragraph). The UF 

applied in acute reference value 

derivation include: (1) Heterogeneity 

among humans; (2) uncertainty in 

extrapolating from animals to humans; 

(3) uncertainty in lowest observed 

adverse effect (exposure) level to no 

observed adverse effect (exposure) level 

adjustments; and (4) uncertainty in 

accounting for an incomplete database 

on toxic effects of potential concern. 

Additional adjustments are often 

applied to account for uncertainty in 

extrapolation from observations at one 

exposure duration (e.g., 4 hours) to 

derive an acute reference value at 

another exposure duration (e.g., 1 hour). 

Not all acute reference values are 

developed for the same purpose and 

care must be taken when interpreting 

the results of an acute assessment of 

human health effects relative to the 

reference value or values being 

exceeded. Where relevant to the 

estimated exposures, the lack of shortterm dose-response values at different 

levels of severity should be factored into 

the risk characterization as potential 

uncertainties. 

Although every effort is made to 

identify peer-reviewed reference values 

for cancer and noncancer effects for all 

pollutants emitted by the sources 

included in this assessment, some HAP 

continue to have no reference values for 

cancer or chronic noncancer or acute 

effects. Since exposures to these 

pollutants cannot be included in a 

quantitative risk estimate, an 

understatement of risk for these 

pollutants at environmental exposure 

levels is possible. For a group of 

compounds that are either unspeciated 

or do not have reference values for every 

individual compound (e.g., glycol 

ethers), we conservatively use the most 

protective reference value to estimate 

risk from individual compounds in the 

group of compounds. 

Additionally, chronic reference values 

for several of the compounds included 

in this assessment are currently under 

the EPA IRIS review and revised 

assessments may determine that these 

pollutants are more or less potent than 

the current value. We may re-evaluate 

residual risks for the final rulemaking if 

these reviews are completed prior to our 

taking final action for these source 

categories and a dose-response metric 

changes enough to indicate that the risk 

assessment supporting this notice may 

significantly understate human health 

risk. 

v. Uncertainties in the Multi-Pathway 

and Environmental Effects Assessment 

We generally assume that when 

exposure levels are not anticipated to 

adversely affect human health, they also 

are not anticipated to adversely affect 

the environment. For each source 

category, we generally rely on the sitespecific levels of PB–HAP emissions to 

determine whether a full assessment of 

the multi-pathway and environmental 

effects is necessary. As discussed above, 

we conclude that the potential for these 

types of impacts is low for these source 

categories. 

vi. Uncertainties in the Facility-Wide 

Risk Assessment 

Given that the same general analytical 

approach and the same models were 

used to generate facility-wide risk 

results as were used to generate the 

source category risk results, the same 

types of uncertainties discussed above 

for our source category risk assessments 

apply to the facility-wide risk 

assessments. Additionally, the degree of 

uncertainty associated with facilitywide emissions and risks is likely 

greater because we generally have not 

conducted a thorough engineering 

review of emissions data for source 

categories not currently undergoing an 

RTR review. 

vii. Uncertainties in the Demographic 

Analysis 

Our analysis of the distribution of 

risks across various demographic groups 

is subject to the typical uncertainties 

associated with census data (e.g., errors 

in filling out and transcribing census 

forms), as well as the additional 

uncertainties associated with the 

extrapolation of census-block group data 

(e.g., income level and education level) 

down to the census block level. 

2. What are the results and proposed 

decisions from the risk review for the 

Oil and Natural Gas Production source 

category? 

a. Results of the Risk Assessments and 

Analyses 

We conducted an inhalation risk 

assessment for the Oil and Natural Gas 

Production source category. We also 

conducted an assessment of facilitywide risk. Details of the risk 

assessments and analyses can be found 

in the residual risk documentation, 

which is available in the docket for this 

action. For informational purposes and 

to examine the potential for any EJ 

issues that might be associated with 

each source category, we performed a 

demographic analysis of population 

risks. 

i. Inhalation Risk Assessment Results 

Table 2 provides an overall summary 

of the results of the inhalation risk 

assessment. 

TABLE 2—OIL AND NATURAL GAS PRODUCTION INHALATION RISK ASSESSMENT RESULTS

Number of 

facilities 1

Maximum individual cancer risk 

(in 1 million) 2 Estimated population at risk ≥ 

1-in-1 million 

Estimated 

annual cancer 

incidence 

(cases per 

year) 

Maximum chronic noncancer 

TOSHI 4 Maximum 

off-site acute 

Actual emis- noncancer HQ 5

sions level 

Allowable emissions level Actual emissions level Allowable emissions level 

990 40 100–400 3 160,000 3 0.007–0.02 3 0.1 0.7 HQREL = 9 

(benzene) 

HQAEGL–1 = 

0.07 (benzene) 

1 Number of facilities evaluated in the risk analysis. 

2Estimated maximum individual excess lifetime cancer risk. 

3The EPA IRIS assessment for benzene provides a range of equally-plausible URE (2.2E–06 to 7.8E–06 per ug/m3), giving rise to ranges for 

the estimates of cancer MIR and cancer incidence. Estimated population values are not scalable with benzene URE range, but would be lower 

using the lower end of the URE range. 4 Maximum TOSHI. The target organ with the highest TOSHI for the Oil and Natural Gas Production source category is the respiratory system. 

5The maximum estimated acute exposure concentration was divided by available short-term dose-response values to develop an array of HQ 

values. 


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36We note that there is an ongoing IRIS 

reassessment for formaldehyde, and that future RTR 

risk assessments will use the cancer potency for 

formaldehyde that results from that reassessment. 

As a result, the current results may not match those 

of future assessments. 

As shown in Table 2, the results of the 

inhalation risk assessment performed 

using actual emissions data indicate the 

maximum lifetime individual cancer 

risk could be as high as 40-in-1 million, 

with POM driving the highest risk, and 

benzene driving risks overall. The total 

estimated cancer incidence from this 

source category is 0.02 excess cancer 

cases per year (0.007 excess cancer cases 

per year based on the lower end of the 

benzene URE range), or one case in 

every 50 years. Approximately 160,000 

people are estimated to have cancer 

risks at or above 1-in-1 million as a 

result of the emissions from 89 facilities 

(use of the lower end of the benzene 

URE range would further reduce this 

population estimate). The maximum 

chronic non-cancer TOSHI value for the 

source category could be up to 0.1 from 

emissions of naphthalene, indicating no 

significant potential for chronic 

noncancer impacts. 

As explained above, our analysis of 

potential differences between actual 

emission levels and emissions allowable 

under the oil and natural gas production 

MACT standard indicate that MACTallowable emission levels may be up to 

50 times greater than actual emission 

levels. Considering this difference, the 

risk results from the inhalation risk 

assessment indicate the maximum 

lifetime individual cancer risk could be 

as high as 400-in-1 million (100-in-1 

million based on the lower end of the 

benzene URE range) and the maximum 

chronic noncancer TOSHI value could 

be as high as 0.7 at the MACT-allowable 

emissions level. 

ii. Facility-Wide Risk Assessment 

Results 

A facility-wide risk analysis was also 

conducted based on actual emissions 

levels. Table 3 displays the results of the 

facility-wide risk assessment. For 

detailed facility-specific results, see 

Table 2 of Appendix 6 of the risk 

document in the docket for this 

rulemaking. 

TABLE 3—OIL AND NATURAL GAS PRODUCTION FACILITY-WIDE RISK ASSESSMENT RESULTS

Number of facilities analyzed .................................................................................................................................................................. 990 

Cancer Risk: 

Estimated maximum facility-wide individual cancer risk (in 1 million) ............................................................................................. 100 

Number of facilities with estimated facility-wide individual cancer risk of 100-in-1 million or more ................................................ 1 

Number of facilities at which the Oil and Natural Gas Production source category contributes 50 percent or more to the facility-wide individual cancer risks of 100-in-1 million or more ......................................................................................................... 0 

Number of facilities with facility-wide individual cancer risk of 1-in-1 million or more ..................................................................... 140 

Number of facilities at which the Oil and Natural Gas Production source category contributes 50 percent or more to the facility-wide individual cancer risk of 1-in-1 million or more ............................................................................................................... 85 

Chronic Noncancer Risk: 

Maximum facility-wide chronic noncancer TOSHI ........................................................................................................................... 9 

Number of facilities with facility-wide maximum noncancer TOSHI greater than 1 ........................................................................ 10 

Number of facilities at which the Oil and Natural Gas Production source category contributes 50 percent or more to the facility-wide maximum noncancer TOSHI of 1 or more ...................................................................................................................... 0 

The facility-wide MIR from all HAP 

emissions at a facility that contains 

sources subject to the oil and natural gas 

production MACT standards is 

estimated to be 100-in-1 million, based 

on actual emissions. Of the 990 facilities 

included in this analysis, only one has 

a facility-wide MIR of 100-in-1 million. 

At this facility, oil and natural gas 

production accounts for less than 2 

percent of the total facility-wide risk. 

Nickel emissions from oil-fired boilers 

and formaldehyde emissions from 

reciprocating internal combustion 

engines (RICE) contribute essentially all 

the facility-wide risks at this facility, 

with over 80 percent of the risk 

attributed to the nickel emissions.36

There are 140 facilities with facilitywide MIR of 1-in-1 million or greater. Of 

these facilities, 85 have oil and natural 

gas production operations that 

contribute greater than 50 percent to the 

facility-wide risks. As discussed above, 

we are proposing MACT standards for 

BTEX emissions from small glycol 

dehydrators in this action. These 

standards would reduce the risk from 

benzene emissions at facilities with oil 

and gas production. Formaldehyde 

emissions will be assessed under future 

RTR for RICE. 

The facility-wide maximum 

individual chronic noncancer TOSHI is 

estimated to be 9 based on actual 

emissions. Of the 990 facilities included 

in this analysis, 10 have facility-wide 

maximum chronic noncancer TOSHI 

values greater than 1. Of these facilities, 

none had oil and natural gas production 

operations that contributed greater than 

50 percent to these facility-wide risks. 

The chronic noncancer risks at these 10 

facilities are primarily driven by 

acrolein emissions from RICE. 

iii. Demographic Risk Analysis Results 

The results of the demographic 

analyses performed to investigate the 

distribution of cancer risks at or above 

1-in-1 million among the surrounding 

population are summarized in Table 4 

below. These results, for various 

demographic groups, are based on 

actual emissions levels for the 

population living within 50 km of the 

facilities. 

TABLE 4—OIL AND NATURAL GAS PRODUCTION DEMOGRAPHIC RISK ANALYSIS RESULTS

Nationwide 

Population with cancer risk at or 

above 1-in-1 million due to 

Source category 

HAP emissions 

Facility-wide HAP 

emissions 

Total Population ......................................................................................................... 285,000,000 160,000 597,000 


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TABLE 4—OIL AND NATURAL GAS PRODUCTION DEMOGRAPHIC RISK ANALYSIS RESULTS—Continued 

Nationwide 

Population with cancer risk at or 

above 1-in-1 million due to 

Source category 

HAP emissions 

Facility-wide HAP 

emissions 

Race by Percent 

White .......................................................................................................................... 75 62 61 

All Other Races ......................................................................................................... 25 38 39 

Race by Percent 

White .......................................................................................................................... 75 62 61 

African American ....................................................................................................... 12 12 8 

Native American ........................................................................................................ 0.9 0.7 1.3 

Other and Multiracial ................................................................................................. 12 25 30 

Ethnicity by Percent 

Hispanic ..................................................................................................................... 14 22 34 

Non-Hispanic ............................................................................................................. 86 78 66 

Income by Percent 

Below Poverty Level .................................................................................................. 13 14 19 

Above Poverty Level .................................................................................................. 87 86 81 

Education by Percent 

Over 25 and without High School Diploma ............................................................... 13 10 16 

Over 25 and with a High School Diploma ................................................................. 87 90 84 

The results of the Oil and Natural Gas 

Production source category 

demographic analysis indicate that there 

are approximately 160,000 people 

exposed to a cancer risk at or above 1- 

in-1 million due to emissions from the 

source category, including an estimated 

38 percent that are classified as minority 

(listed as ‘‘All Other Races’’ in the table 

above). Of the 160,000 people with 

estimated cancer risks at or above 1-in1 million from the source category, 25 

percent are in the ‘‘Other and 

Multiracial’’ demographic group, 22 

percent are in the ‘‘Hispanic or Latino’’ 

demographic group, and 14 percent are 

in the ‘‘Below Poverty Level’’ 

demographic group, results which are 

13, 8 and 1 percentage points higher, 

respectively, than the respective 

percentages for these demographic 

groups across the United States. The 

percentages for the other demographic 

groups are lower than their respective 

nationwide percentages. The table also 

shows that there are approximately 

597,000 people exposed to an estimated 

cancer risk at or above 1-in-1 million 

due to facility-wide emissions, 

including 30 percent in the ‘‘Other and 

Multiracial’’ demographic group, 34 

percent in the ‘‘Hispanic or Latino’’ 

demographic group, 1.3 percent in the 

‘‘Native American’’ demographic group 

and 16 percent in the ‘‘Over 25 and 

without High School Diploma’’ 

demographic group, results which are 

18, 2, 0.4 and 3 percentage points higher 

than the percentages for these 

demographic groups across the United 

States, respectively. The percentages for 

the other demographic groups are lower 

than their respective nationwide 

percentages. 

b. What are the proposed risk decisions 

for the Oil and Natural Gas Production 

source category? 

i. Risk Acceptability 

In the risk analysis we performed for 

this source category, pursuant to CAA 

section 112(f)(2), we considered the 

available health information—the MIR; 

the numbers of persons in various risk 

ranges; cancer incidence; the maximum 

noncancer HI; the maximum acute 

noncancer hazard; the extent of 

noncancer risks; the potential for 

adverse environmental effects; and 

distribution of risks in the exposed 

population; and risk estimation 

uncertainty (54 FR 38044, September 

14, 1989). 

For the Oil and Natural Gas 

Production source category, the risk 

analysis we performed indicates that the 

cancer risks to the individual most 

exposed could be as high as 40-in-1 

million due to actual emissions and as 

high as 400-in-1 million due to MACTallowable emissions (100-in-1 million, 

based on the lower end of the benzene 

URE range). While the 40-in-1 million 

risk due to actual emissions is 

considerably less than 100-in-1 million, 

which is the presumptive limit of 

acceptability, the 400-in-1 million risk 

due to allowable emissions is 

considerably higher and is considered 

unacceptable. We do note, however, that 

the risk analysis shows low cancer 

incidence (1 case in every 50 years), low 

potential for adverse environmental 

effects or human health multi-pathway 

effects and that chronic noncancer 

health impacts are unlikely. 

We also conclude that acute 

noncancer health impacts are unlikely. 

As discussed above, screening estimates 

of acute exposures and risks were 

evaluated for each of the HAP at the 

point of highest off-site exposure for 

each facility (i.e., not just the census 

block centroids) assuming that a person 

is located at this spot at a time when 

both the peak emission rate and worstcase dispersion conditions occur. Under 

these worst-case conditions, we estimate 

benzene acute HQ values (based on the 

REL) could be as high as 9. Although the 

REL (which indicates the level below 

which adverse effects are not 

anticipated) is exceeded in this case, we 

believe the potential for acute effects is 

low for several reasons. First, the acute 

modeling scenario is worst-case because 

of the confluence of peak emission rates 

and worst-case dispersion conditions. 


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Second, the benzene REL is based on a 

6-hour exposure duration because a 

1-hour exposure duration value was 

unavailable. An REL based on a 6-hour 

exposure duration is generally lower 

than an REL based on a 1-hour exposure 

duration and, consequently, easier to 

exceed. Also, although there are 

exceedances of the REL, the highest 

estimated 1-hour exposure is less than 

10 percent of the AEGL–1 value, which 

is a level at which effects could be 

experienced. Finally, the generally 

sparse populations near these facilities 

make it less likely that a person would 

be near the plant to be exposed. For 

example, in the two cases where the 

acute HQ value is as high as 9, there are 

only 30 people associated with the 

census blocks within 2 miles of the two 

facilities. 

While our additional analysis of 

facility-wide risks showed that there is 

one facility with maximum facility-wide 

cancer risk of 100-in-1 million or greater 

and 10 facilities with a maximum 

chronic noncancer TOSHI greater than 

1, it also showed that oil and natural gas 

production operations did not drive 

these risks. 

In determining whether risk is 

acceptable, we considered the available 

health information, as described above. 

In this case, although a number of 

factors we considered indicate relatively 

low risk concern, we are proposing to 

determine that the risks are 

unacceptable, in large part, because the 

MIR is 400-in-1 million due to MACTallowable emissions, which greatly 

exceeds the ‘‘presumptive limit on 

maximum individual lifetime risk of 

approximately 1-in-10 thousand [100-in1 million] recognized in the Benzene 

NESHAP (54 FR 38045).’’ The MIR, 

based on MACT-allowable emissions, is 

driven by the allowable emissions of 0.9 

Mg/yr benzene under the MACT as a 

compliance option. We are, therefore, 

proposing to eliminate the alternative 

compliance option of 0.9 Mg/yr benzene 

from the existing glycol dehydrator 

MACT requirements. With this change, 

the source category MIR, based on 

MACT-allowable emissions, would be 

reduced to 40-in-1 million, which we 

find acceptable in light of all the other 

factors considered. Thus, we are 

proposing that the risks from the Oil 

and Natural Gas Production source 

category are acceptable, with the 

removal of the alternative compliance 

option of 0.9 Mg/yr benzene limit from 

the current glycol dehydrator MACT 

requirements. 

Pursuant to CAA section 112(f)(4), we 

are proposing that this change (i.e., 

removal of the 0.9 Mg/yr compliance 

alternative) apply 90 days after its 

effective date. We are requesting 

comment on whether or not this is 

sufficient time for the large dehydrators 

that have been relying on this 

compliance alternative to come into 

compliance with the 95-percent control 

requirement or if additional time is 

needed. See CAA section 112(f)(4)(A). 

We recognize that our proposal to 

remove the 0.9 Mg/yr compliance 

alternative for the 95-percent control 

glycol dehydrator MACT standard could 

have negative impacts on some sources 

that have come to rely on the flexibility 

this alternative provides. We solicit 

comment on any such impacts and 

whether such impacts warrant adding a 

different compliance alternative that 

would result in less risk than the 0.9 

Mg/yr benzene limit compliance option. 

If a commenter suggests a different 

compliance alternative, the commenter 

should explain, in detail, what that 

alternative would be, how it would 

work and how it would reduce risk. 

ii. Ample Margin of Safety 

We next considered whether this 

revised standard (existing MACT plus 

removal of 0.9 Mg/yr benzene 

compliance option) provides an ample 

margin of safety. In this analysis, we 

investigated available emissions control 

options that might reduce the risk 

associated with emissions from the 

source category and considered this 

information along with all of the health 

risks and other health information 

considered in the risk acceptability 

determination. 

For glycol dehydrators, we considered 

the addition of a second control device 

in the same manner that was discussed 

in the floor evaluation in section VII.B.1 

above. The cost effectiveness associated 

with that option would be $167,200/Mg, 

which we believe is too high to require 

additional controls on glycol 

dehydrators. 

Similarly, we considered the addition 

of a second control device to the 

required MACT floor control device 

(cost effectiveness of $18,300/Mg). 

Similar to our discussion of beyond-theMACT-floor controls for glycol 

dehydrators in section VII.B.1 of this 

preamble, the incremental cost to add a 

second control device for storage vessels 

would be approximately 20 times higher 

than the MACT floor cost effectiveness, 

or $366,000/Mg. We do not believe this 

cost effectiveness is reasonable. 

For leak detection, we considered 

implementation of LDAR programs that 

are more stringent than the current 

standards. An assessment performed for 

various LDAR options under the NSPS 

in section VI.B.4.b of this preamble 

yielded the lowest cost effectiveness of 

$5,170/Mg ($4,700/ton) for control of 

VOC for the options evaluated. A LDAR 

program to control HAP would involve 

similar costs for equipment, labor, etc., 

to those considered in the NSPS 

assessment, but since there is 

approximately 20 times less HAP than 

VOC present in material handled in 

regulated equipment, the cost 

effectiveness to control HAP would be 

approximately 20 times greater (i.e., 

$100,000/Mg) for HAP, which we 

believe is not reasonable. 

In accordance with the approach 

established in the Benzene NESHAP, 

the EPA weighed all health risk 

measures and information considered in 

the risk acceptability determination, 

along with the costs and economic 

impacts of emissions controls, 

technological feasibility, uncertainties 

and other relevant factors in making our 

ample margin of safety determination. 

Considering the health risk information 

and the high cost effectiveness of the 

options identified, we propose that the 

existing MACT standards, with the 

removal of the 1 tpy benzene limit 

compliance option from the glycol 

dehydrator standards, provide an ample 

margin of safety to protect public health. 

While we are proposing that the oil 

and natural gas production MACT 

standards (with the removal of the 

alternative compliance option of 1 tpy 

benzene limit) provide an ample margin 

of safety to protect public health, we are 

concerned about the estimated facilitywide risks identified through these 

screening analyses. As described 

previously, the highest estimated 

facility-wide cancer risks are mostly due 

to emissions from oil fired boilers and 

RICE. Both of these sources are 

regulated under other source categories 

and we anticipate that emission 

reductions from those sources will 

occur as standards for those source 

categories are implemented. 

3. What are the results and proposed 

decisions from the risk review for the 

Natural Gas Transmission and Storage 

source category? 

a. Results of the Risk Assessments and 

Analyses 

We conducted an inhalation risk 

assessment for the Natural Gas 

Transmission and Storage source 

category. We also conducted an 

assessment of facility-wide risk and 

performed a demographic analysis of 

population risks. Details of the risk 

assessments and analyses can be found 

in the residual risk documentation, 

which is available in the docket for this 

action. 


emcdonald on DSK2BSOYB1PROD with PROPOSALS2
Federal Register / Vol. 76, No. 163 / Tuesday, August 23, 2011 / Proposed Rules 52781 

i. Inhalation Risk Assessment Results 

Table 5 provides an overall summary 

of the results of the inhalation risk 

assessment. For informational purposes 

and to examine the potential for any EJ 

issues that might be associated with 

each source category, we performed a 

demographic analysis of population 

risks. 

TABLE 5—NATURAL GAS TRANSMISSION AND STORAGE INHALATION RISK ASSESSMENT RESULTS

Number of 

Facilities 1

Maximum individual cancer risk 

(in 1 million) 2 Estimated 

population at 

risk ≥ 1-in-1 

million 

Estimated 

annual cancer 

incidence 

(cases per 

year) 

Maximum chronic noncancer 

TOSHI 4 Maximum 

off-site acute 

Actual noncancer HQ 5

emissions level 

Allowable emissions level Actual 

emissions level 

Allowable emissions level 

321 3 30–90 3 30–90 3 2,500 3 0.0003–0.001 0.4 0.8 HQREL = 5 

(benzene) 

HQAEGL–1 = 0.2 

(chlorobenzene) 

1 Number of facilities evaluated in the risk analysis. 

2Estimated maximum individual excess lifetime cancer risk. 

3The EPA IRIS assessment for benzene provides a range of equally-plausible URE (2.2E–06 to 7.8E–06 per ug/m3), giving rise to ranges for 

the estimates of cancer MIR and cancer incidence. Estimated population values are not scalable with benzene URE range, but would be lower 

using the lower end of the URE range. 4 Maximum TOSHI. The target organ with the highest TOSHI for the Natural Gas Transmission and Storage source category is the immune 

system. 5The maximum estimated acute exposure concentration was divided by available short-term dose-response values to develop an array of HQ 

values. 

As shown in Table 5 above, the 

results of the inhalation risk assessment 

performed using actual emissions data 

indicate the maximum lifetime 

individual cancer risk could be as high 

as 90-in-1 million, (30-in-1 million 

based on the lower end of the benzene 

URE range), with benzene as the major 

contributor to the risk. The total 

estimated cancer incidence from the 

source category is 0.001 excess cancer 

cases per year (0.0003 excess cancer 

cases per year based on the lower end 

of the benzene URE range), or one case 

in every polycyclic organic matter 1,000 

years. Approximately 2,500 people are 

estimated to have cancer risks at or 

above 1-in-1 million as a result of the 

emissions from 15 facilities (use of the 

lower end of the benzene URE range 

would further reduce this population 

estimate). The maximum chronic 

noncancer TOSHI value for the source 

category could be up to 0.4 from 

emissions of benzene, indicating no 

significant potential for chronic 

noncancer impacts. 

As explained above in section 

VII.C.1.b, our analysis of potential 

differences between actual emission 

levels and emissions allowable under 

the natural gas transmission and storage 

MACT standard indicate that MACTallowable emission levels may be up to 

50 times greater than actual emission 

levels at some sources. However, 

because some sources are emitting at the 

level allowed under the current 

NESHAP, the risk results from the 

inhalation risk assessment indicate the 

maximum lifetime individual cancer 

risk would still be 90-in-1 million (30- 

in-1 million based on the lower end of 

the benzene URE range), based on both 

actual and allowable emission levels, 

and the maximum chronic noncancer 

TOSHI value could be as high as 0.8 at 

the MACT-allowable emissions level. 

ii. Facility-Wide Risk Assessment 

Results 

A facility-wide risk analysis was also 

conducted based on actual emissions 

levels. Table 6 below displays the 

results of the facility-wide risk 

assessment. For detailed facility-specific 

results, see Table 2 of Appendix 6 of the 

risk document in the docket for this 

rulemaking. 

TABLE 6—NATURAL GAS TRANSMISSION AND STORAGE FACILITY-WIDE RISK ASSESSMENT RESULTS

Number of Facilities Analyzed ................................................................................................................................................................. 321 

Cancer Risk: 

Estimated maximum facility-wide individual cancer risk (in 1 million) ............................................................................................. 1 200 

Number of facilities with estimated facility-wide individual cancer risk of 100-in-1 million or more ................................................ 3 

Number of facilities at which the Natural Gas Transmission and Storage source category contributes 50 percent or more to 

the facility-wide individual cancer risks of 100-in-1 million or more ............................................................................................. 1 

Number of facilities with facility-wide individual cancer risk of 1-in-1 million or more ..................................................................... 74 

Number of facilities at which the Natural Gas Transmission and Storage source category contributes 50 percent or more to 

the facility-wide individual cancer risk of 1-in-1 million or more ................................................................................................... 10 

Chronic Noncancer Risk: 

Maximum facility-wide chronic noncancer TOSHI ........................................................................................................................... 80 

Number of facilities with facility-wide maximum noncancer TOSHI greater than 1 ........................................................................ 30 

Number of facilities at which the Natural Gas Transmission and Storage source category contributes 50 percent or more to 

the facility-wide maximum noncancer TOSHI of 1 or more ......................................................................................................... 0 

1We note that the MIR would be 100-in-1 million if the CIIT URE for formaldehyde were used instead of the IRIS URE. 

The facility-wide MIR from all HAP 

emissions at any facility that contains 

sources subject to the natural gas 

transmission and storage MACT 

standards is estimated to be 200-in-1 

million, based on actual emissions. Of 

the 321 facilities included in this 

analysis, three have facility-wide MIR of 

100-in-1 million or greater. The facilitywide MIR is 200-in-1 million at two of 

these facilities, driven by formaldehyde 


emcdonald on DSK2BSOYB1PROD with PROPOSALS2
52782 Federal Register / Vol. 76, No. 163 / Tuesday, August 23, 2011 / Proposed Rules 

37We note that there is an ongoing IRIS 

reassessment for formaldehyde, and that future RTR 

risk assessments will use the cancer potency for 

formaldehyde that results from that reassessment. 

As a result, the current results may not match those 

of future assessments. 

from RICE.37 Another facility has a 

facility-wide risk of 100-in-1 million, 

with 90 percent of the risk attributed to 

natural gas transmission and storage. 

There are 74 facilities with facility-wide 

MIR of 1-in-1 million or greater. Of 

these facilities, 10 have natural gas 

transmission and storage operations that 

contribute greater than 50 percent to the 

facility-wide risks. As discussed above, 

we are proposing MACT standards for 

benzene emissions from small glycol 

dehydrators in this action. These 

standards would reduce the risk from 

benzene emissions at facilities with 

natural gas transmission and storage 

operations. The facility-wide cancer 

risks at the facilities with risks of 1-in1 million or more are primarily driven 

by formaldehyde emissions from RICE, 

which will be assessed in a future RTR 

for that category. 

The facility-wide maximum 

individual chronic noncancer TOSHI is 

estimated to be 80, based on actual 

emissions. Of the 321 facilities included 

in this analysis, 30 have facility-wide 

maximum chronic noncancer TOSHI 

values greater than 1. Of these facilities, 

none had natural gas transmission and 

storage operations that contributed 

greater than 50 percent to these facilitywide risks. The chronic noncancer risks 

at these facilities are primarily driven by 

acrolein emissions from RICE. 

iii. Demographic Risk Analysis Results 

The results of the demographic 

analyses performed to investigate the 

distribution of cancer risks at or above 

1-in-1 million among the surrounding 

population are summarized in Table 7 

below. These results, for various 

demographic groups, are based on 

actual emissions levels for the 

population living within 50 km of the 

facilities. 

TABLE 7—NATURAL GAS TRANSMISSION AND STORAGE DEMOGRAPHIC RISK ANALYSIS RESULTS

Nationwide 

Population with cancer risk at or 

above 1-in-1 million due to . . . 

Source category 

HAP emissions 

Facility-wide HAP 

emissions 

Total Population ......................................................................................................... 285,000,000 2,500 99,000 

Race by Percent 

White .......................................................................................................................... 75 92 58 

All Other Races ......................................................................................................... 25 8 42

Race by Percent 

White .......................................................................................................................... 75 92 58 

African American ....................................................................................................... 12 6 40 

Native American ........................................................................................................ 0.9 0.1 0.2 

Other and Multiracial ................................................................................................. 12 1 2 

Ethnicity by Percent 

Hispanic ..................................................................................................................... 14 1 2 

Non-Hispanic ............................................................................................................. 86 99 98 

Income by Percent 

Below Poverty Level .................................................................................................. 13 17 20 

Above poverty level ................................................................................................... 87 83 80 

Education by Percent 

Over 25 and without High School Diploma ............................................................... 13 20 15 

Over 25 and with a High School Diploma ................................................................. 87 80 85 

The results of the Natural Gas 

Transmission and Storage source 

category demographic analysis indicate 

that there are approximately 2,500 

people exposed to a cancer risk at or 

above 1-in-1 million due to emissions 

from the source category, including an 

estimated 8 percent that are classified as 

minority (listed as ‘‘All Other Races’’ in 

Table 7 above). Of the 2,500 people with 

estimated cancer risks at or above 1-in1 million from the source category, 17 

percent are in the ‘‘Below Poverty 

Level’’ demographic group, and 20 

percent are in the ‘‘Over 25 and without 

High School Diploma’’ demographic 

group, results which are 4 and 7 

percentage points higher, respectively, 

than the percentages for these 

demographic groups across the United 

States. The percentages for the other 

demographic groups are lower than 

their respective nationwide percentages. 

The table also shows that there are 

approximately 99,000 people exposed to 

an estimated cancer risk at or above 1- 

in-1 million due to facility-wide 

emissions, including an estimated 42 

percent that are classified as minority 

(‘‘All Other Races’’ in Table 7 above). Of 

the 99,000 people with estimated cancer 

risk at or above 1-in-1 million from 

facility-wide emissions, 40 percent are 

in the ‘‘African American’’ demographic 

group, 20 percent are in the ‘‘Below 

Poverty Level’’ demographic group, and 

15 percent are in the ‘‘Over 25 and 

without High School Diploma’’ 

demographic group, results which are 

28, 7 and 2 percentage points higher, 

respectively, than the percentages for 

these demographic groups across the 

United States. The percentages for the 

other demographic groups are equal to 


emcdonald on DSK2BSOYB1PROD with PROPOSALS2
Federal Register / Vol. 76, No. 163 / Tuesday, August 23, 2011 / Proposed Rules 52783 

or lower than their respective 

nationwide percentages. 

b. What are the proposed risk decisions 

for the Natural Gas Transmission and 

Storage source category? 

i. Risk Acceptability 

In the risk analysis we performed for 

this source category, pursuant to CAA 

section 112(f)(2), we considered the 

available health information—the MIR; 

the numbers of persons in various risk 

ranges; cancer incidence; the maximum 

noncancer HI; the maximum acute 

noncancer hazard; the extent of 

noncancer risks; the potential for 

adverse environmental effects; 

distribution of risks in the exposed 

population; and risk estimation 

uncertainty (54 FR 38044, September 

14, 1989). 

For the Natural Gas Transmission and 

Storage source category, the risk 

analysis we performed indicates that the 

cancer risks to the individual most 

exposed could be as high as 90-in-1 

million due to actual and allowable 

emissions (30-in-1 million, based on the 

lower end of the benzene URE range). 

These risks are near 100-in-1 million, 

which is the presumptive limit of 

acceptability. On the other hand, the 

risk analysis shows low cancer 

incidence (1 case in every 1,000 years), 

low potential for adverse environmental 

effects or human health multi-pathway 

effects and that chronic and acute 

noncancer health impacts are unlikely. 

We conclude that acute noncancer 

health impacts are unlikely for reasons 

similar to those described in section 

VII.C.2.b.i of this preamble. 

Our additional analysis of facilitywide risks showed that, among three 

facilities with maximum facility-wide 

cancer risk of 100-in-1 million or 

greater, one facility has a facility-wide 

cancer risk of 100-in-1 million, with 90 

percent of the risk attributed to natural 

gas and transmission and storage. There 

are 30 facilities with a maximum 

chronic noncancer TOSHI greater than 

1, but natural gas transmission and 

storage operations did not drive this 

risk. 

In determining whether risk is 

acceptable, we considered the available 

health information, as described above. 

In this case, because the MIR is 

approaching, but still less than 100-in1 million risk, and because a number of 

other factors indicate relatively low risk 

concern (e.g., low cancer incidence, low 

potential for adverse environmental 

effects or human health multi-pathway 

effects, chronic and acute noncancer 

health impacts unlikely), we are 

proposing to determine that the risks are 

acceptable. 

ii. Ample Margin of Safety 

We next considered whether the 

existing MACT standard provides an 

ample margin of safety. In this analysis, 

we investigated available emissions 

control options that might reduce the 

risk associated with emissions from the 

source category and considered this 

information, along with all of the health 

risks and other health information 

considered in the risk acceptability 

determination. The estimated MIR of 90- 

in-1 million discussed above is driven 

by the 0.9 Mg/year benzene limit 

compliance alternative for the glycol 

dehydrator MACT standard in the 

current NESHAP. Removal of this 

compliance alternative would lower the 

MIR for the source category to 20-in-1 

million. We, therefore, considered 

removing this compliance alternative as 

an option for reducing risk and assessed 

the cost of such alternative. Without the 

compliance alternative, affected glycol 

dehydrators (i.e., those units with 

annual average benzene emissions of 0.9 

Mg/yr or greater and an annual average 

natural gas throughput of 283,000 scmd 

or greater) must demonstrate 

compliance with the 95-percent control 

requirement, which we believe can be 

shown with their existing control 

devices in most cases, although, in some 

instances, installation of a different or 

an additional control may be necessary. 

In section VII.B.1 above, we discuss 

the costs for requiring controls on 

currently unregulated ‘‘small glycol 

dehydrators,’’ which are similar, in 

operation and type of emission controls, 

to the dehydrators subject to the current 

MACT (‘‘large dehydrators’’). The HAP 

cost effectiveness determined for small 

dehydrators at the floor level of control 

was $1,650/Mg. Although control 

methodologies are similar for large and 

small dehydrators, we expect that the 

costs for controls on large units could be 

as much as twice as high as for small 

units because of the large gas flow being 

processed. However, we also expect that 

the amount of HAP emission reduction 

for the large dehydrators, in general, to 

be as much as, or more than, the amount 

achieved by small dehydrators. In light 

of the above, we do not expect the cost 

effectiveness of the control device 

needed to meet the 95-percent control 

requirement for large dehydrators to 

exceed $3,300/Mg (i.e., twice the cost 

effectiveness for small dehydrators), 

which we consider to be reasonable. 

In accordance with the approach 

established in the Benzene NESHAP, 

the EPA weighed all health risk 

measures and information considered in 

the risk acceptability determination, 

along with the costs and economic 

impacts of emissions controls, 

technological feasibility, uncertainties 

and other relevant factors in making our 

ample margin of safety determination. 

Considering the health risk information 

and the reasonable cost effectiveness of 

the option identified, we propose that 

the existing MACT standards, with the 

removal of the 0.9 Mg benzene limit 

compliance option from the glycol 

dehydrator standards, provide an ample 

margin of safety to protect public health. 

Pursuant to CAA section 112(f)(4), we 

are proposing that this change (i.e., 

removal of the 0.9 Mg/yr compliance 

alternative) apply 90 days after its 

effective date. We are requesting 

comment on whether or not there is 

sufficient time for the large dehydrators 

that have been relying on this 

compliance alternative to come into 

compliance with the 95-percent control 

requirement or if additional time is 

needed. See CAA section 112(f)(4)(A). 

We recognize that our proposal to 

remove the one-ton compliance 

alternative for the 95-percent control 

glycol dehydrator MACT standard could 

have negative impacts on some sources 

that have come to rely on the flexibility 

this alternative provides. We solicit 

comment on any such impacts and 

whether such impacts warrant adding a 

different compliance alternative that 

would result in less risk than the 0.9 

Mg/yr benzene limit compliance option. 

If a commenter suggests a different 

compliance alternative, the commenter 

should explain, in detail, what that 

alternative would be, how it would 

work, and how it would reduce risk. 

As described above, we are proposing 

that the natural gas transmission and 

storage MACT standards (with the 

removal of the 0.9 Mg/yr benzene limit 

compliance option) provide an ample 

margin of safety to protect public health. 

We recognize that one facility has a 

facility-wide cancer risk of 100-in-1 

million, with 90 percent of the risk 

attributed to natural gas transmission 

and storage. This risk is driven by 

benzene emissions from glycol 

dehydrators and is being addressed by 

our proposed revision to the Natural Gas 

Transmission and Storage NESHAP 

(removal of the 0.9 Mg/yr benzene limit 

compliance option). As previously 

mentioned, two facilities have facilitywide MIR of 200-in-1 million, driven by 

formaldehyde from RICE. Emissions 

from RICE are regulated under another 

source category and will be assessed 

under a future RTR for that category. 


emcdonald on DSK2BSOYB1PROD with PROPOSALS2
52784 Federal Register / Vol. 76, No. 163 / Tuesday, August 23, 2011 / Proposed Rules 

38As stated above in section VI.B.1, emissions for 

the two options using the optical gas imaging 

camera alone cannot be quantified and, therefore, 

no cost effectiveness values were determined. 

D. How did we perform the technology 

review and what are the results and 

proposed decisions? 

1. What was the methodology for the 

technology review? 

Our technology review is focused on 

the identification and evaluation of 

‘‘developments in practices, processes, 

and control technologies’’ since the 

promulgation of the MACT standards 

for the two oil and gas source categories. 

If a review of available information 

identifies such developments, then we 

conduct an analysis of the technical 

feasibility of requiring the 

implementation of these developments, 

along with the impacts (costs, emission 

reductions, risk reductions, etc.). We 

then make a decision on whether it is 

necessary to amend the regulation to 

require these developments. 

Based on specific knowledge of each 

source category, we began by identifying 

known developments in practices, 

processes and control technologies. For 

the purpose of this exercise, we 

considered any of the following to be a 

‘‘development’’: 

• Any add-on control technology or 

other equipment that was not identified 

and considered during MACT 

development; 

• Any improvements in add-on 

control technology or other equipment 

(that was identified and considered 

during MACT development) that could 

result in significant additional emission 

reduction; 

• Any work practice or operational 

procedure that was not identified and 

considered during MACT development; 

and 

• Any process change or pollution 

prevention alternative that could be 

broadly applied that was not identified 

and considered during MACT 

development. 

In addition to looking back at 

practices, processes or control 

technologies reviewed at the time we 

developed the MACT standards, we 

reviewed a variety of sources of data to 

aid in our evaluation of whether there 

were additional practices, processes or 

controls to consider. One of these 

sources of data was subsequent air 

toxics rules. Since the promulgation of 

the MACT standards for the source 

categories addressed in this proposal, 

the EPA has developed air toxics 

regulations for a number of additional 

source categories. We reviewed the 

regulatory requirements and/or 

technical analyses associated with these 

subsequent regulatory actions to 

identify any practices, processes and 

control technologies considered in these 

efforts that could possibly be applied to 

emission sources in the source 

categories under this current RTR 

review. 

We also consulted the EPA’s RBLC. 

The terms ‘‘RACT,’’ ‘‘BACT,’’ and 

‘‘LAER’’ are acronyms for different 

program requirements under the CAA 

provisions addressing the NAAQS. 

Control technologies classified as RACT, 

BACT or LAER apply to stationary 

sources depending on whether the 

source exists or is new and on the size, 

age and location of the facility. The 

BACT and LAER (and sometimes RACT) 

are determined on a case-by-case basis, 

usually by state or local permitting 

agencies. The EPA established the RBLC 

to provide a central database of air 

pollution technology information 

(including technologies required in 

source-specific permits) to promote the 

sharing of information among 

permitting agencies and to aid in 

identifying future possible control 

technology options that might apply 

broadly to numerous sources within a 

category or apply only on a source-bysource basis. The RBLC contains over 

5,000 air pollution control permit 

determinations that can help identify 

appropriate technologies to mitigate 

many air pollutant emission streams. 

We searched this database to determine 

whether any practices, processes or 

control technologies are included for the 

types of processes used for emission 

sources (e.g., spray booths) in the source 

categories under consideration in this 

proposal. 

We also consulted information from 

the Natural Gas STAR program. The 

Natural Gas STAR program is a flexible, 

voluntary partnership that encourages 

oil and natural gas companies to adopt 

cost effective technologies and practices 

that improve operational efficiency and 

reduce pollutant emissions. The 

program provides the oil and gas 

industry with information on new 

techniques and developments to reduce 

pollutant emissions from the various 

processes. 

2. What are the results and proposed 

decisions from the technology review? 

There are three types of emission 

sources covered by the two oil and gas 

NESHAP. These sources and the control 

technologies (including add-on control 

devices and process modifications) 

considered during the development of 

the MACT standards are: Glycol 

dehydrators (combustion devices, 

recovery devices, process 

modifications), storage vessels with the 

PFE (combustion devices, recovery 

devices) and equipment leaks (LDAR 

programs, specific equipment 

modifications). Dehydrators are 

addressed by both 40 CFR part 63, 

subpart HH and 40 CFR part 63, subpart 

HHH, while equipment leaks and 

storage vessels with the PFE are only 

covered by subpart HH. 

Since the promulgation of 40 CFR part 

63, subpart HH, which established 

MACT standards to address HAP 

emissions from equipment leaks at gas 

processing plants, the EPA has 

developed LDAR programs that are 

more stringent than what is required in 

subpart HH. The most prevalent 

differences between these more 

stringent programs and subpart HH 

relate to the frequency of monitoring 

and the concentration which constitutes 

a ‘‘leak.’’ We do consider these 

programs to represent a development in 

practices and evaluated whether to 

revise the MACT standards for 

equipment leaks at natural gas 

processing plants under subpart HH in 

light of this development. 

An analysis was performed above in 

section VI.B.1 to assess the VOC 

reduction, costs and other impacts 

associated with these more stringent 

LDAR program options at natural gas 

processing plants. One option 

considered was to require compliance 

with 40 CFR part 60, subpart VVa 

instead of 40 CFR part 60, subpart VV 

(the current NSPS requirement for 

equipment leaks of VOC at natural gas 

processing plants), which changes the 

leak definition (based on methane) from 

10,000 ppm to 500 ppm and requires 

monitoring of connectors. Because the 

current leak definition under NESHAP 

40 CFR part 63, subpart HH is the same 

as that in NSPS subpart VV, and the 

ratio of VOC to HAP is approximately 

20 to 1, we expect that the HAP 

reduction would be 1/20th of the VOC 

reduction under subpart VVa. The 

estimated incremental cost for that 

option was determined to be $3,340 per 

ton of VOC. Based on the 20-to-1 ratio, 

we estimate the incremental cost to 

control HAP at the subpart VVa level 

would be approximately $66,800 per ton 

of HAP ($73,480/Mg). Other options 

considered in section VI.B.1 of this 

preamble (and the incremental cost of 

each option for reducing HAP) are as 

follows: The use of an optical gas 

imaging camera monthly with an annual 

EPA Method 21 check ($129,000 per ton 

of HAP/$143,600 per Mg, if purchasing 

the camera; $93,000 per ton of HAP/ 

$103,300 per Mg, if renting the camera); 

monthly optical gas imagining alone; 

and annual optical gas imaging.38 In 


emcdonald on DSK2BSOYB1PROD with PROPOSALS2
Federal Register / Vol. 76, No. 163 / Tuesday, August 23, 2011 / Proposed Rules 52785 

39Because optical gas imaging is used to view 

several pieces of equipment at a facility at once to 

survey for leaks, options involving imaging are not 

amenable to a component by component analysis. 

light of the above, we do not believe that 

the additional costs of these programs 

are justified. 

In addition to the plant-wide 

evaluations, a component analysis was 

also evaluated at gas processing plants 

for the 40 CFR part 60, subpart VValevel of control (option 1 considered in 

section VI.B.1).39 That assessment 

shows that the subpart VVa-level of 

control for connectors has an 

incremental cost effectiveness of $4,360 

per ton for VOC for connectors and $144 

per ton for VOC for valves. This means 

the incremental cost to control HAP 

would be approximately $87,200 per ton 

($96,900/Mg) for connectors and $2,880 

per ton ($3,200/Mg) for valves. We do 

not believe the additional cost for the 

more stringent requirement for 

connectors is justified, but the 

additional cost for valves is justified. 

Therefore, we are proposing to revise 

the equipment leak requirements in 40 

CFR part 63, subpart HH to lower the 

leak definition for valves to an 

instrument reading of at least 500 ppm 

as a result of our technology review. 

Some of the practices, processes or 

control technologies listed by the 

Natural Gas STAR program applicable 

to the emission sources in these 

categories were not identified and 

evaluated during the original MACT 

development. While the Natural Gas 

STAR program does contain information 

regarding new innovative techniques 

that are available to reduce HAP 

emissions, they are not considered to 

have emission reductions higher than 

what is set by the original MACT. One 

control technology identified in the 

Natural Gas STAR program that would 

result in no HAP emissions from glycol 

dehydration units would be the 

replacement of a glycol dehydration 

unit with a desiccant dehydrator. This 

technology cannot be used for natural 

gas operations with gas streams having 

high temperature, high volume, and low 

pressure. Due to the limitations posed 

by these conditions, we do not consider 

desiccant dehydrators as MACT. 

For storage vessels, the applicable 

technologies identified by the Gas STAR 

program, which are evaluated above for 

proposal under NSPS in section VI.B.4, 

are similar to the cover and control 

technologies currently required for 

storage vessels under the existing 

MACT. Therefore, these technologies 

would not result in any further 

emissions reductions than what is 

achieved by the original MACT. 

Our review of the RBLC did not 

identify any practices, processes and 

control technologies applicable to the 

emission sources in these categories that 

were not identified and evaluated 

during the original MACT development. 

In light of the above, we are not 

proposing any revisions to the existing 

MACT standards for storage vessels 

pursuant to section 112(d)(6) of the 

CAA. 

E. What other actions are we proposing? 

1. Combustion Control Device Testing 

As explained below in section VII.E.2, 

under our proposal, performance testing 

would be required initially and every 5 

years for non-condenser control devices. 

However, for certain enclosed 

combustion control devices, we are 

proposing to allow, as an alternative to 

on-site testing, a performance test 

conducted by a control device 

manufacturer in accordance with the 

procedures provided in this proposal. 

We propose to allow a unit whose 

model meets the proposed performance 

criteria to claim a BTEX or HAP 

destruction efficiency of 98 percent at 

the facility. This value is lower than the 

99.9-percent destruction efficiency 

required in the manufacturers’ test due 

to variations between the test fuel 

specified and the gas streams combusted 

at the actual facility. A source subject to 

the small dehydrator BTEX limit would 

use the 98-percent destruction 

efficiency to calculate their dehydrator’s 

BTEX emissions for the purpose of 

demonstrating compliance. For the 

95-percent control MACT standard, a 

control device matching the tested 

model would be considered to meet that 

requirement. Once a device has been 

demonstrated to meet the proposed 

performance criteria (and, therefore, is 

assigned a 98-percent destruction 

efficiency), installation of a unit 

matching the tested model at a facility 

would require no further performance 

testing (i.e., periodic tests would not be 

required every 5 years). 

We are proposing this alternative to 

minimize issues associated with 

performance testing of certain 

combustion control devices. We believe 

that testing units that are not configured 

with a distinct combustion chamber 

present several technical issues that are 

more optimally addressed through 

manufacturer testing, and once these 

units are installed at a facility, through 

periodic inspection and maintenance in 

accordance with manufacturers’ 

recommendations. One issue is that an 

extension above certain existing 

combustion control device enclosures 

will be necessary to get adequate 

clearance above the flame zone. Such 

extensions can more easily be 

configured by the manufacturer of the 

control device rather than having to 

modify an extension in the field to fit 

devices at every site. Issues related to 

transporting, installing and supporting 

the extension in the field are also 

eliminated through manufacturer 

testing. Another concern is that the pitot 

tube used to measure flow can be 

altered by radiant heat from the flame 

such that gas flow rates are not accurate. 

This issue is best overcome by having 

the manufacturer select and use the 

pitot tube best suited to their specific 

unit. For these reasons, we believe the 

manufacturers’ test is appropriate for 

these control devices with ongoing 

performance ensured by periodic 

inspection and maintenance. 

This proposed alternative does not 

apply to flares, as defined in 40 CFR 

63.761 and 40 CFR 63.1271, which must 

demonstrate compliance by meeting the 

design and operation requirements in 40 

CFR 63.11(b), 40 CFR 63.772(e)(2) and 

40 CFR 63.1282(d)(2). It also would not 

apply to thermal oxidizers having a 

combustion chamber/firebox where 

combustion temperature and residence 

time can be measured during an on-site 

performance test and are valid 

indicators of performance. These 

thermal oxidizers do not present the 

issues described above relative to onsite performance testing and, therefore, 

do not need an alternative testing 

option. The proposed alternative would, 

therefore, apply to enclosed combustion 

control devices except for these thermal 

oxidizers. 

In conjunction with the proposed 

manufacturer testing alternative, we are 

proposing to add a definition for flare to 

clarify that flares, as referenced in the 

NESHAP (and to which the proposed 

testing alternative does not apply), 

refers to a thermal oxidation system 

with an open flame (i.e., without 

enclosure). Accordingly, any thermal 

oxidation system that does not meet the 

proposed flare definition would be 

considered an enclosed combustion 

control device. 

We estimate that there are many 

existing facilities currently using 

enclosed combustion control devices 

that would be required to either conduct 

an on-site performance test or install 

and operate a control device tested by 

the manufacturer under our proposal. 

Given the estimated number of these 

combustion control devices in use, the 

time required for manufacturers to test 

and manufacture such units, we are 

proposing that existing sources have up 

to 3 years from the date of the final 

rules’ publication date to comply with 


emcdonald on DSK2BSOYB1PROD with PROPOSALS2
52786 Federal Register / Vol. 76, No. 163 / Tuesday, August 23, 2011 / Proposed Rules 

40The design analysis alternative in the existing 

MACT does not apply to flares. As previously 

mentioned, the existing MACT provides separate 

design and operation requirements for flares. 

the initial performance testing 

requirements. 

2. Monitoring, Recordkeeping and 

Reporting 

We are proposing to make changes to 

the monitoring requirements described 

below to address issues we have 

identified through a monitoring 

sufficiency review performed during the 

RTR process. First, we are including 

calibration procedures associated with 

parametric monitoring requirements in 

the existing NESHAP. The NESHAP 

require parametric monitoring of control 

device parameters (e.g., temperatures or 

flowrate monitoring), but did not 

include information on calibration or 

included inadequate information on 

calibration of monitoring devices. 

Therefore, we are specifying the 

calibration requirements for temperature 

and flow monitors that the NESHAP 

currently lacks. 

In addition, under the current 

NESHAP, a design analysis can be used 

in lieu of performance testing to 

demonstrate compliance and establish 

operating parameter limits. We are 

proposing to allow the use of the design 

evaluation alternative only when the 

control device being used is a 

condenser. The design evaluation 

option is appropriate for condensers 

because their emissions can be 

accurately predicted using readily 

available physical property information 

(e.g., vapor pressure data and 

condensation calculations). In those 

cases, one would not need to conduct 

emissions testing to determine actual 

emissions to demonstrate compliance 

with the MACT standard. For example, 

a requirement that ‘‘the temperature at 

the outlet of the condenser shall be 

maintained at 50° Fahrenheit below the 

condensation temperature calculated for 

the compound of interest using the 

reference equation’’ (e.g., National 

Institute of Standards and Technology 

Chemistry WebBook at http:// 

webbook.nist.gov/chemistry/) is 

adequate to assure proper operation of 

the condenser and, therefore, 

compliance with the required emission 

standard. 

For other types of control 

technologies, such as carbon adsorption 

systems and enclosed combustion 

devices,40 the ability to predict 

emissions depends on data developed 

by the vendor and such data may not 

reliably result in an accurate prediction 

of emissions from a specific facility. 

There are variables (e.g., air to fuel 

ratios and waste constituents for 

combustion; varying organic 

concentrations, constituents and 

capacity issues, including break-through 

for carbon adsorption) that make 

theoretical predictions less reliable. The 

effects of these site-specific variables on 

emissions are not easily predictable and 

establishing monitoring conditions (e.g., 

combustion temperature, vacuum 

regeneration) based on vendor data will 

likely not account for those variables. 

Therefore, we propose to eliminate the 

design evaluation alternative for noncondenser controls. 

For non-condenser controls (and 

condensers not using the design 

analysis option), in addition to the 

initial compliance testing, we are 

proposing that performance tests be 

conducted at least once every 5 years 

and whenever sources desire to 

establish new operating limits. Under 

the current NESHAP, a performance test 

is only conducted in two instances: (1) 

As an alternative to a design analysis for 

their compliance demonstration and 

identification of operating parameter 

ranges and (2) as a requirement to 

resolve a disagreement between the EPA 

and the owner or operator regarding the 

design analysis. The current NESHAP 

do not require additional performance 

testing beyond these two cases (i.e., 

there is no periodic testing 

requirement). As mentioned above, we 

are proposing to remove the design 

evaluation option for non-condenser 

controls. For non-condenser controls 

(and condensers not using the design 

analysis option), the proposed periodic 

testing would ensure compliance with 

the emission standards by verifying that 

the control device is meeting the 

necessary HAP destruction efficiency 

determined in the initial performance 

test. As discussed above in section 

VII.E.1, we are proposing that 

combustion control devices tested under 

the manufacturers’ procedure are not 

required to conduct periodic testing. In 

addition, we are also proposing that 

combustion control devices that can 

demonstrate a uniform combustion zone 

temperature meeting the required 

control efficiency during the initial 

performance test are exempt from 

periodic testing. The requirement for 

continuous monitoring of combustion 

zone temperature is an accurate 

indicator of control device performance 

and eliminates the need for future 

testing. 

The current NESHAP (40 CFR 

63.771(d) and 40 CFR 63.1281(d)) 

require operating an enclosed 

combustion device at a minimum 

residence time of 0.5 seconds at a 

minimum temperature of 760 degrees 

Celsius. We are proposing to remove the 

residence time requirement. The 

residence time requirement is not 

needed because the compliance 

demonstration made during the 

performance test is sufficient to ensure 

that the combustion device has adequate 

residence time to ensure the needed 

destruction efficiency. Therefore, we are 

proposing to remove the residence time 

requirement. 

We are also clarifying at 40 CFR 

63.773(d)(3)(i) and 40 CFR 

63.1283(d)(3)(i) for thermal vapor 

incinerators, boilers and process 

heaters, that the temperature sensor 

shall be installed at a location 

representative of the combustion zone 

temperature. Currently, the regulation 

requires that the temperature sensor be 

installed at a location ‘‘downstream of 

the combustion zone’’ because we had 

thought that the temperature 

downstream would be representative of 

combustion zone temperature. We have 

now learned that may or may not be the 

case. We are, therefore, proposing to 

amend this provision to more accurately 

reflect the intended requirement. 

Next, consistent with revisions for 

SSM, we’ve revised 40 CFR 

63.771(d)(4)(i) and 40 CFR 

63.1281(d)(4)(i), except when 

maintenance or repair on a unit cannot 

be completed without a shutdown of the 

control device. 

Also, we’ve updated the criteria for 

prior performance test results that can 

be used to demonstrate compliance in 

lieu of conducting a performance test. 

These updates ensure that data for 

determining compliance are accurate, 

up-to-date, and truly representative of 

actual operating conditions. 

In addition, we are proposing to 

revise the temperature monitoring 

device minimum accuracy criteria in 40 

CFR 63.773(d)(3)(i) to better reflect the 

level of performance that is required of 

the temperature monitoring devices. We 

believe that temperature monitoring 

devices currently used to meet the 

requirements of the NESHAP can meet 

the proposed revised criteria without 

modification. 

Also, we are proposing to revise the 

calibration gas concentration for the no 

detectable emissions procedure 

applicable to closed vent systems in 40 

CFR 63.772(c)(4)(ii) from 10,000 ppmv 

to 500 ppmv methane to be consistent 

with the leak threshold of 500 ppmv in 

40 CFR part 63, subpart HH. The current 

calibration level is inconsistent with 

achieving accurate readings at the level 

necessary to demonstrate there are no 

detectable emissions. 


emcdonald on DSK2BSOYB1PROD with PROPOSALS2
Federal Register / Vol. 76, No. 163 / Tuesday, August 23, 2011 / Proposed Rules 52787 

Also, we are proposing recordkeeping 

and reporting requirements for carbon 

adsorption systems. The current 

NESHAP require the replacement of all 

carbon in the carbon adsorption system 

with fresh carbon on a regular, 

predetermined time interval that is no 

longer than the carbon service life 

established for the carbon system, but 

provide no recordkeeping or reporting 

requirement to document and assure 

compliance with this standard. We 

believe that maintaining some sort of log 

book is a reasonable alternative 

combined with a requirement to report 

instances when specified practices are 

not followed. Therefore, the proposed 

rule adds reporting and recordkeeping 

requirements for establishing a schedule 

and maintaining logs of carbon 

replacement. 

Finally, as noted above in section 

VII.B.1, we are proposing a BTEX 

emissions limit for small glycol 

dehydration unit process vents. For the 

compliance demonstration, we propose 

that parametric monitoring of the 

control device be performed. We believe 

that parametric monitoring is adequate 

for glycol dehydrators in these two 

source categories because temperature 

monitoring, whether it be to verify 

proper condenser or combustion device 

operation, is a reliable indicator of 

performance for reducing organic HAP 

emissions. We also considered the use 

of a continuous emissions monitoring 

system (CEMS) to monitor compliance. 

However, for glycol dehydrators in the 

oil and natural gas sector, the necessary 

electricity, weather-protective 

enclosures and daily staffing are not 

usually available. We, therefore, 

question the technical feasibility of 

operating a CEMS correctly in this 

sector. We request comment on the 

practicality of including provisions in 

the final rule for a CEMS to monitor 

BTEX emissions for small glycol 

dehydration units. 

3. Startup, Shutdown, Malfunction 

The United States Court of Appeals 

for the District of Columbia Circuit 

vacated portions of two provisions in 

the EPA’s CAA section 112 regulations 

governing the emissions of HAP during 

periods of SSM. Sierra Club v. EPA, 551 

F.3d 1019 (D.C. Cir. 2008), cert. denied, 

130 S. Ct. 1735 (U.S. 2010). Specifically, 

the Court vacated the SSM exemption 

contained in 40 CFR 63.6(f)(1) and 40 

CFR 63.6(h)(1), that is part of a 

regulation, commonly referred to as the 

General Provisions Rule, that the EPA 

promulgated under section 112 of the 

CAA. When incorporated into CAA 

section 112(d) regulations for specific 

source categories, these two provisions 

exempt sources from the requirement to 

comply with the otherwise applicable 

CAA section 112(d) emission standard 

during periods of SSM. 

We are proposing the elimination of 

the SSM exemption in the two oil and 

gas NESHAP. Consistent with Sierra 

Club v. EPA, the EPA is proposing to 

apply the standards in these NESHAP at 

all times. In addition, we are proposing 

to revise 40 CFR 63.771(d)(4)(i) and 40 

CFR 63.1281(d)(4)(i) to remove the 

provision allowing shutdown of the 

control device during maintenance or 

repair. We are also proposing several 

revisions to the General Provisions 

applicability table for the MACT 

standard. For example, we are 

proposing to eliminate the incorporation 

of the General Provisions’ requirement 

that the source develop a SSM plan. We 

are also proposing to eliminate or revise 

certain recordkeeping and reporting 

requirements related to the SSM 

exemption. The EPA has attempted to 

ensure that we have not included in the 

proposed regulatory language any 

provisions that are inappropriate, 

unnecessary or redundant in the 

absence of the SSM exemption. We are 

specifically seeking comment on 

whether there are any such provisions 

that we have inadvertently incorporated 

or overlooked. 

In proposing the MACT standards in 

these rules, the EPA has taken into 

account startup and shutdown periods. 

We believe that operations and 

emissions do not differ from normal 

operations during these periods such 

that it warrants a separate standard. 

Therefore, we have not proposed 

different standards for these periods. 

Periods of startup, normal operations 

and shutdown are all predictable and 

routine aspects of a source’s operations. 

However, by contrast, malfunction is 

defined as a ‘‘sudden, infrequent and 

not reasonably preventable failure of air 

pollution control and monitoring 

equipment, process equipment or a 

process to operate in a normal or usual 

manner * * *’’ (40 CFR 63.2). The EPA 

has determined that malfunctions 

should not be viewed as a distinct 

operating mode and, therefore, any 

emissions that occur at such times do 

not need to be factored into 

development of CAA section 112(d) 

standards, which, once promulgated, 

apply at all times. In Mossville 

Environmental Action Now v. EPA, 370 

F.3d 1232, 1242 (D.C. Cir. 2004), the 

Court upheld as reasonable, standards 

that had factored in variability of 

emissions under all operating 

conditions. However, nothing in CAA 

section 112(d) or in case law requires 

that the EPA anticipate and account for 

the innumerable types of potential 

malfunction events in setting emission 

standards. See Weyerhaeuser v. Costle, 

590 F.2d 1011, 1058 (D.C. Cir. 1978), 

(‘‘In the nature of things, no general 

limit, individual permit, or even any 

upset provision can anticipate all upset 

situations. After a certain point, the 

transgression of regulatory limits caused 

by ‘‘uncontrollable acts of third parties,’’ 

such as strikes, sabotage, operator 

intoxication or insanity, and a variety of 

other eventualities, must be a matter for 

the administrative exercise of case-bycase enforcement discretion, not for 

specification in advance by 

regulation.’’). 

Further, it is reasonable to interpret 

CAA section 112(d) as not requiring the 

EPA to account for malfunctions in 

setting emissions standards. For 

example, we note that CAA section 112 

uses the concept of ‘‘best performing’’ 

sources in defining MACT, the level of 

stringency that major source standards 

must meet. Applying the concept of 

‘‘best performing’’ to a source that is 

malfunctioning presents significant 

difficulties. The goal of best performing 

sources is to operate in such a way as 

to avoid malfunctions of their units. 

Moreover, even if malfunctions were 

considered a distinct operating mode, 

we believe it would be impracticable to 

take malfunctions into account in 

setting CAA section 112(d) standards for 

oil and natural gas production facility 

and natural gas transmission and storage 

operations. As noted above, by 

definition, malfunctions are sudden and 

unexpected events, and it would be 

difficult to set a standard that takes into 

account the myriad different types of 

malfunctions that can occur across all 

sources in each source category. 

Moreover, malfunctions can also vary in 

frequency, degree and duration, further 

complicating standard setting. 

In the event that a source fails to 

comply with the applicable CAA section 

112(d) standards as a result of a 

malfunction event, the EPA would 

determine an appropriate response 

based on, among other things, the good 

faith efforts of the source to minimize 

emissions during malfunction periods, 

including preventative and corrective 

actions, as well as root cause analyses 

to ascertain and rectify excess 

emissions. The EPA would also 

consider whether the source’s failure to 

comply with the CAA section 112(d) 

standard was, in fact, ‘‘sudden, 

infrequent, not reasonably preventable’’ 

and was not instead ‘‘caused in part by 

poor maintenance or careless 

operation.’’ 40 CFR 63.2 (definition of 

malfunction). 


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52788 Federal Register / Vol. 76, No. 163 / Tuesday, August 23, 2011 / Proposed Rules 

Finally, the EPA recognizes that even 

equipment that is properly designed and 

maintained can sometimes fail and that 

such failure can sometimes cause or 

contribute to an exceedance of the 

relevant emission standard. (See, e.g., 

State Implementation Plans: Policy 

Regarding Excessive Emissions During 

Malfunctions, Startup, and Shutdown 

(September 20, 1999); Policy on Excess 

Emissions During Startup, Shutdown, 

Maintenance, and Malfunctions 

(February 15, 1983)). The EPA is, 

therefore, proposing to add to the final 

rule an affirmative defense to civil 

penalties for exceedances of emission 

limits that are caused by malfunctions 

in both of the MACT standards 

addressed in this proposal. See 40 CFR 

63.761 for sources subject to the oil and 

natural gas production MACT 

standards, or 40 CFR 63.1271 for 

sources subject to the natural gas 

transmission and storage MACT 

standards (defining ‘‘affirmative 

defense’’ to mean, in the context of an 

enforcement proceeding, a response or 

defense put forward by a defendant, 

regarding which the defendant has the 

burden of proof and the merits of which 

are independently and objectively 

evaluated in a judicial or administrative 

proceeding). We also are proposing 

other regulatory provisions to specify 

the elements that are necessary to 

establish this affirmative defense; a 

source subject to the oil and natural gas 

production facilities or natural gas 

transmission MACT standards must 

prove by a preponderance of the 

evidence that it has met all of the 

elements set forth in 40 CFR 63.762 and 

a source subject to the natural gas 

transmission and storage facilities 

MACT standards must prove by a 

preponderance of the evidence that it 

has met all of the elements set forth in 

40 CFR 63.1272. (See 40 CFR 22.24.) 

The criteria ensure that the affirmative 

defense is available only where the 

event that causes an exceedance of the 

emission limit meets the narrow 

definition of malfunction in 40 CFR 63.2 

(sudden, infrequent, not reasonably 

preventable and not caused by poor 

maintenance and or careless operation). 

For example, to successfully assert the 

affirmative defense, the source must 

prove by a preponderance of evidence 

that excess emissions ‘‘[w]ere caused by 

a sudden, infrequent, and unavoidable 

failure of air pollution control and 

monitoring equipment, process 

equipment, or a process to operate in a 

normal or usual manner * * *.’’ The 

criteria also are designed to ensure that 

steps are taken to correct the 

malfunction, to minimize emissions in 

accordance with 40 CFR 63.762 for 

sources subject to the oil and natural gas 

production facilities MACT standards or 

40 CFR 63.1272 for sources subject to 

the natural gas transmission and storage 

facilities MACT standards and to 

prevent future malfunctions. For 

example, the source must prove by a 

preponderance of evidence that 

‘‘[r]epairs were made as expeditiously as 

possible when the applicable emission 

limitations were being exceeded * * *’’ 

and that ‘‘[a]ll possible steps were taken 

to minimize the impact of the excess 

emissions on ambient air quality, the 

environment and human health * * *.’’ 

In any judicial or administrative 

proceeding, the Administrator may 

challenge the assertion of the affirmative 

defense and, if the respondent has not 

met its burden of proving all of the 

requirements in the affirmative defense, 

appropriate penalties may be assessed 

in accordance with section 113 of the 

CAA (see also 40 CFR 22.77). 

4. Applicability and Compliance 

a. Calculating Potential To Emit (PTE) 

We are proposing to amend section 40 

CFR 63.760(a)(1)(iii) to clarify that 

sources must use a glycol circulation 

rate consistent with the definition of 

PTE in 40 CFR 63.2 in calculating 

emissions for purposes of determining 

PTE. Affected parties have 

misinterpreted the current language 

concerning measured values or annual 

average to apply to a broader range of 

parameters than was intended. Those 

qualifiers were meant to apply to gas 

characteristics that are measured, such 

as inlet gas composition, pressure and 

temperature rather than process 

equipment settings. That means that the 

circulation rate used in PTE 

determinations shall be the maximum 

under its physical and operational 

design. 

In addition to the proposed changes 

described above, we are seeking 

comment on several PTE related issues. 

According to the data available to the 

Administrator, when 40 CFR part 63, 

subpart HH was promulgated, the level 

of HAP emissions was predominantly 

driven by natural gas throughput (i.e., 

HAP emissions went up or down in 

concert with natural gas throughput). 

Since promulgation, we have learned 

that there is not always a direct 

correlation between HAP emissions and 

natural gas throughput. We have 

received information suggesting that, in 

some cases, HAP emissions can increase 

despite decreasing natural gas 

throughput due to changes in gas 

composition. We are asking for 

comment regarding the likelihood of 

this occurrence and data demonstrating 

the circumstances where it occurs. In 

light of the potential issue, we are 

asking for comment regarding the 

addition of provisions in the NESHAP 

to require area sources to recalculate 

their PTE to confirm that they are 

indeed area sources and whether that 

calculation should be performed on an 

annual or biannual basis to verify that 

changes in gas composition have not 

increased their emissions. 

b. Definition of Facility and 

Applicability Criteria 

Subpart HH of 40 CFR part 63 (section 

63.760(a)(2)) currently defines facilities 

as those where hydrocarbon liquids are 

processed, upgraded or stored prior to 

the point of custody transfer or where 

natural gas is processed, upgraded or 

stored prior to entering the Natural Gas 

Transmission and Storage source 

category. We are proposing to remove 

the references to ‘‘point of custody 

transfer’’ and ‘‘transmission and storage 

source categories’’ from the definition 

because the operations performed at a 

site sufficiently define a facility and the 

scope of the subpart is specified already 

under 40 CFR 63.760. In addition, we 

are removing the custody transfer 

reference from the applicability criteria 

in 40 CFR 63.760(a)(2). Since 

hydrocarbon liquids can pass through 

several custody transfer points between 

the well and the final destination, the 

custody transfer criteria is not clear 

enough. We are, therefore, proposing to 

replace the reference to ‘‘point of 

custody transfer’’ with a more specific 

description of the point up to which the 

subpart applies (i.e., the point where 

hydrocarbon liquids enter either the 

organic liquids distribution or 

petroleum refineries source categories) 

and exclude custody transfer from that 

criteria. We believe this change 

eliminates ambiguity and is consistent 

with the oil and natural gas productionspecific provisions in the organic 

liquids distribution MACT. 

5. Other Proposed Changes To Clarify 

These Rules 

The following lists additional changes 

to the NESHAP we are proposing. This 

list includes proposed rule changes that 

address editorial corrections and plain 

language revisions: 

• Revise 40 CFR 63.769(b) to clarify 

that the equipment leak provisions in 40 

CFR part 63, subpart HH do not apply 

to a source if that source is required to 

control equipment leaks under either 40 

CFR part 63, subpart H or 40 CFR part 

60, subpart KKK. The current 40 CFR 

63.769(b), which states that subpart HH 

does not apply if a source meets the 


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Federal Register / Vol. 76, No. 163 / Tuesday, August 23, 2011 / Proposed Rules 52789 

requirements in either of the subparts 

mentioned above, does not clearly 

express our intent that such source must 

be implementing the LDAR provisions 

in the other 40 CFR part 60 or 40 CFR 

part 63 subparts to qualify for the 

exemption. 

• Revise 40 CFR 63.760(a)(1) to 

clarify that an existing area source that 

increases its emissions to major source 

levels has up to the first substantive 

compliance date to either reduce its 

emissions below major source levels by 

obtaining a practically enforceable 

permit or comply with the applicable 

major source provisions of 40 CFR part 

63, subpart HH. We have revised the 

second to last sentence in 40 CFR 

63.760(a)(1) by removing the 

parenthetical statement because it 

simply reiterates the last sentence of 

this section and is, therefore, 

unnecessary. 

• Revise 40 CFR 63.771(d)(1)(ii) and 

40 CFR 63.1281(d)(1)(ii) to clarify that 

the vapor recovery device and ‘‘other 

control device’’ described in those 

provisions refer to non-destructive 

control devices only. 

• Revise the last sentence of 40 CFR 

63.764(i) and 40 CFR 63.1274(g) to 

clarify the requirements following an 

unsuccessful attempt to repair a leak. 

• Updated the e-mail and physical 

address for area source reporting in 40 

CFR 63.775(c)(1). 

VIII. What are the cost, environmental, 

energy and economic impacts of the 

proposed 40 CFR part 60, subpart 

OOOO and amendments to subparts HH 

and HHH of 40 CFR part 63? 

We are presenting a combined 

discussion of the estimates of the 

impacts for the proposed 40 CFR part 

60, subpart OOOO and proposed 

amendments to 40 CFR part 63, subpart 

HH and 40 CFR part 63, subpart HHH. 

The cost, environmental and economic 

impacts presented in this section are 

expressed as incremental differences 

between the impacts of an oil and 

natural gas facility complying with the 

amendments to subparts HH and HHH 

and new standards under 40 CFR 60, 

subpart OOOO and the baseline, i.e., the 

standards before these amendments. 

The impacts are presented for the year 

2015, which will be the year that all 

existing oil and natural gas facilities 

will have to be in compliance, and also 

the year that will represent 

approximately 5 years of construction of 

new oil and natural gas facilities subject 

to the NSPS emissions limits. The 

analyses and the documents referenced 

below can be found in Docket ID 

Numbers EPA–HQ–OAR–2007–0877 

and EPA–HQ–OAR–2002–0051. 

A. What are the affected sources? 

We expect that by 2015, the year 

when all existing sources will be 

required to come into compliance in the 

United States, there will be 97 oil and 

natural gas production facilities and 15 

natural gas transmission and storage 

facilities with one or more existing 

glycol dehydration units. We also 

estimate that there will be an additional 

329 (there are 47 facilities that already 

have an affected glycol dehydration 

unit) existing oil and natural gas 

production facilities with existing 

storage vessels that we expect to be 

affected by these final amendments. 

These facilities operate approximately 

134 glycol dehydration units (115 in 

production and 19 in transmission and 

storage) and 1,970 storage vessels. 

Approximately 10 oil and natural gas 

production and two transmission and 

storage facilities would have new glycol 

dehydration units and 38 production 

facilities would have new dehydration 

units. We expect new production 

facilities would operate approximately 

12 production glycol dehydration units 

and 197 storage vessels and new 

transmission and storage would operate 

approximately two glycol dehydration 

units. 

Based on data provided by the United 

States Energy Information 

Administration, we anticipate that by 

2015 there will be approximately 21,800 

gas wellhead facilities, 790 

reciprocating compressors, 30 

centrifugal compressors, 14,000 

pneumatic devices and 300 storage 

vessels subject to the new NSPS for 

VOC. Some of these affected facilities 

will be built at existing facilities and 

some at new greenfield facilities. Based 

on data limitations, we assume impacts 

are equal regardless of location. 

There are about 21 glycol dehydration 

units with high enough HAP emissions 

that we believe cannot meet the 

emissions limit without using more than 

one control technique. In developing the 

cost impacts, we assume that they 

would require multiple controls. The 

controls for which we have detailed cost 

data are condensers and VRU, so we 

developed costs for both controls to 

develop what we consider to be a 

reasonable cost estimate for these 

facilities. This does not imply that we 

believe these facilities will specifically 

use a combination of a condenser and 

vapor recovery limit, but we do believe 

the combination of these control results 

is a reasonable estimate of cost. 

B. How are the impacts for this proposal 

evaluated? 

For these proposed Oil and Natural 

Gas Production and Natural Gas 

Transmission and Storage NESHAP 

amendments and NSPS, the EPA used 

two models to evaluate the impacts of 

the regulation on the industry and the 

economy. Typically, in a regulatory 

analysis, the EPA determines the 

regulatory options suitable to meet 

statutory obligations under the CAA. 

Based on the stringency of those 

options, the EPA then determines the 

control technologies and monitoring 

requirements that sources might 

rationally select to comply with the 

regulation. This analysis is documented 

in an engineering analysis. The selected 

control technologies and monitoring 

requirements are then evaluated in a 

cost model to determine the total 

annualized control costs. The 

annualized control costs serve as inputs 

to an Economic Impact Analysis model 

that evaluates the impacts of those costs 

on the industry and society as a whole. 

The Economic Impact Analysis used 

the National Energy Modeling System 

(NEMS) to estimate the impacts of the 

proposed NSPS on the United States 

energy system. The NEMS is a 

publically-available model of the United 

States energy economy developed and 

maintained by the Energy Information 

Administration of the United States 

DOE and is used to produce the Annual 

Energy Outlook, a reference publication 

that provides detailed forecasts of the 

energy economy from the current year to 

2035. The impacts we estimated 

included changes in drilling activity, 

price and quantity changes in the 

production and consumption of crude 

oil and natural gas and changes in 

international trade of crude oil and 

natural gas. We evaluated whether and 

to what extent the increased production 

costs imposed by the NSPS might alter 

the mix of fuels consumed at a national 

level. Additionally, we combined 

estimated emissions co-reductions of 

methane from the engineering analysis 

with NEMS analysis to estimate the net 

change in CO2e GHG from energyrelated sources. 

C. What are the air quality impacts? 

For the oil and natural gas sector 

NESHAP and NSPS, we estimated the 

emission reductions that will occur due 

to the implementation of the final 

emission limits. The EPA estimated 

emission reductions based on the 

control technologies selected by the 

engineering analysis. These emission 

reductions associated with the proposed 

amendments to 40 CFR part 63, subpart 


emcdonald on DSK2BSOYB1PROD with PROPOSALS2
52790 Federal Register / Vol. 76, No. 163 / Tuesday, August 23, 2011 / Proposed Rules 

HH and 40 CFR part 63, subpart HHH 

are based on the estimated population 

in 2008. Under the proposed limits for 

glycol dehydration units and storage 

vessels, we have estimated that the HAP 

emissions reductions will be 1,400 tpy 

for existing units subject to the 

proposed emissions limits. 

For the NSPS, we estimated the 

emission reductions that will occur due 

to the implementation of the final 

emission limits. The EPA estimated 

emission reductions based on the 

control technologies selected by the 

engineering analysis. These emission 

reductions are based on the estimated 

population in 2015. Under the proposed 

NSPS, we have estimated that the 

emissions reductions will be 540,000 

tpy VOC for affected facilities subject to 

the NSPS. 

The control strategies likely adopted 

to meet the proposed NESHAP 

amendments and the proposed NSPS 

will result in concurrent control of HAP, 

methane and VOC emissions. We 

estimate that direct reductions in HAP, 

methane and VOC for the proposed 

rules combined total about 38,000 tpy, 

3.4 million tpy and 540,000 tpy, 

respectively. 

Under the final standards, new 

monitoring requirements are being 

added. 

D. What are the water quality and solid 

waste impacts? 

We estimated minimal water quality 

impacts for the proposed amendments 

and proposed NSPS. For the proposed 

amendments to the NESHAP, we 

anticipate that the water impacts 

associated with the installation of a 

condenser system for the glycol 

dehydration unit process vent would be 

minimal. This is because the condensed 

water collected with the hydrocarbon 

condensate can be directed back into the 

system for reprocessing with the 

hydrocarbon condensate or, if separated, 

combined with produced water for 

disposal, usually by reinjection. 

Similarly, the water impacts 

associated with installation of a vapor 

control system either on a glycol 

dehydration unit or a storage vessel 

would be minimal. This is because the 

water vapor collected along with the 

hydrocarbon vapors in the vapor 

collection and redirect system can be 

directed back into the system for 

reprocessing with the hydrocarbon 

condensate or, if separated, combined 

with the produced water for disposal for 

reinjection. 

There would be no water impacts 

expected for facilities subject to the 

proposed NSPS. Further, we do not 

anticipate any adverse solid waste 

impacts from the implementation of the 

proposed NESHAP amendments and the 

proposed NSPS. 

E. What are the secondary impacts? 

Indirect or secondary air quality 

impacts include impacts that will result 

from the increased electricity usage 

associated with the operation of control 

devices, as well as water quality and 

solid waste impacts (which were just 

discussed) that might occur as a result 

of these proposed actions. We estimate 

the proposed amendments to 40 CFR 

part 63, subpart HH and 40 CFR part 63, 

subpart HHH will increase emissions of 

criteria pollutants due to the potential 

use of flares for the control of storage 

vessels. We do not estimate an increased 

energy demand associated with the 

installation of condensers, VRU or 

flares. The increases in criteria pollutant 

emissions associated with the use of 

flares to control storage vessels subject 

to existing source standards are 

estimated to be 5,500 tpy of CO2, 16 tpy 

of carbon monoxide (CO), 3 tpy of NOX, 

less than 1 tpy of particulate matter 

(PM) and 6 tpy total hydrocarbons. For 

storage vessels subject to new source 

standards, increases in secondary air 

pollutants are estimated to be less than 

900 tpy of CO2, 3 tpy of CO, 1 tpy of 

NOX, 1 tpy of PM and 1 tpy total 

hydrocarbons. 

In addition, we estimate that the 

secondary impacts associated with the 

pneumatic controller requirements to 

comply with the proposed NSPS would 

be about 22 tpy of CO2, 1 tpy of NOX

and 3 tpy PM. For gas wellhead affected 

facilities, we estimate that the use of 

flares would result in increases in 

criteria pollutant emissions of about 

990,000 tons of CO2, 2,800 tpy of CO, 

500 tpy of NOX, 5 tpy of PM and 1,000 

tpy total hydrocarbons. 

F. What are the energy impacts? 

Energy impacts in this section are 

those energy requirements associated 

with the operation of emission control 

devices. Potential impacts on the 

national energy economy from the rule 

are discussed in the economic impacts 

section. There would be little national 

energy demand increase from the 

operation of any of the control options 

analyzed under the proposed NESHAP 

amendments and proposed NSPS. 

The proposed NESHAP amendments 

and proposed NSPS encourage the use 

of emission controls that recover 

hydrocarbon products, such as methane 

and condensate that can be used on-site 

as fuel or reprocessed within the 

production process for sale. We 

estimated that the proposed standards 

will result in a net cost savings due to 

the recovery of salable natural gas and 

condensate. Thus, the final standards 

have a positive impact associated with 

the recovery of non-renewable energy 

resources. 

G. What are the cost impacts? 

The estimated total capital cost to 

comply with the proposed amendments 

to 40 CFR part 63, subpart HH for major 

sources in the Oil and Natural Gas 

Production source category is 

approximately $51.5 million. The total 

capital cost for the proposed 

amendments to 40 CFR part 63, subpart 

HHH for major sources in the Natural 

Gas Transmission and Storage source 

category is estimated to be 

approximately $370 thousand. All costs 

are in 2008 dollars. 

The total estimated net annual cost to 

industry to comply with the proposed 

amendments to 40 CFR part 63, subpart 

HH for major sources in the Oil and 

Natural Gas Production source category 

is approximately $16 million. The total 

net annual cost for proposed 

amendments to 40 CFR part 63, subpart 

HHH for major sources in the Natural 

Gas Transmission and Storage source 

category is estimated to be 

approximately $360,000. These 

estimated annual costs include: (1) The 

cost of capital, (2) operating and 

maintenance costs, (3) the cost of 

monitoring, inspection, recordkeeping 

and reporting (MIRR) and (4) any 

associated product recovery credits. All 

costs are in 2008 dollars. 

The estimated total capital cost to 

comply with the proposed NSPS is 

approximately $740 million in 2008 

dollars. The total estimated net annual 

cost to industry to comply with the 

proposed NSPS is approximately $740 

million in 2008 dollars. This annual 

cost estimate includes: (1) The cost of 

capital, (2) operating and maintenance 

costs and (3) the cost of MIRR. This 

estimated annual cost does not take into 

account any producer revenues 

associated with the recovery of salable 

natural gas and hydrocarbon 

condensates. 

When revenues from additional 

product recovery are considered, the 

proposed NSPS is estimated to result in 

a net annual engineering cost savings 

overall. When including the additional 

natural gas recovery in the engineering 

cost analysis, we assume that producers 

are paid $4 per thousand cubic feet 

(Mcf) for the recovered gas at the 

wellhead. The engineering analysis cost 

analysis assumes the value of recovered 

condensate is $70 per barrel. Based on 

the engineering analysis, about 

180,000,000 Mcf (180 billion cubic feet) 

of natural gas and 730,000 barrels of 


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Federal Register / Vol. 76, No. 163 / Tuesday, August 23, 2011 / Proposed Rules 52791 

41U.S. EPA. RIA. National Ambient Air Quality 

Standards for Particulate Matter, Chapter 5. Office 

of Air Quality Planning and Standards, Research 

Triangle Park, NC. October 2006. Available on the 

Internet at http://www.epa.gov/ttn/ecas/regdata/ 

RIAs/Chapter%205-Benefits.pdf. 

42U.S. EPA. RIA. National Ambient Air Quality 

Standards for Ozone. Office of Air Quality Planning 

and Standards, Research Triangle Park, NC. January 

2010. Available on the Internet at http:// 

www.epa.gov/ttn/ecas/regdata/RIAs/s1- 

supplemental_analysis_full.pdf. 

43U.S. EPA. Integrated Science Assessment for 

Particulate Matter (Final Report). EPA–600–R–08– 

139F. National Center for Environmental 

Assessment—RTP Division. December 2009. 

Available at http://cfpub.epa.gov/ncea/cfm/ 

recordisplay.cfm?deid=216546. 

44U.S. EPA. Air Quality Criteria for Ozone and 

Related Photochemical Oxidants (Final). EPA/600/ 

R–05/004aF–cF. Washington, DC: U.S. EPA. 

February 2006. Available on the Internet at http://

cfpub.epa.gov/ncea/CFM/ 

recordisplay.cfm?deid=149923. 

condensate are estimated to be 

recovered by control requirements in 

2015. Using the price assumptions, the 

estimated revenues from natural gas 

product recovery are approximately 

$780 million in 2008 dollars. This 

savings is estimated at $45 million in 

2008 dollars. 

Using the engineering cost estimates, 

estimated natural gas product recovery, 

and natural gas product price 

assumptions, the net annual engineering 

cost savings is estimated for the 

proposed NSPS at about $45 million in 

2008 dollars. Totals may not sum due to 

independent rounding. 

As the price assumption is very 

influential on estimated annualized 

engineering costs, we performed a 

simple sensitivity analysis of the 

influence of the assumed wellhead price 

paid to natural gas producers on the 

overall engineering annualized costs 

estimate of the proposed NSPS. At 

$4.22/Mcf, the price forecast reported in 

the 2011 Annual Energy Outlook in 

2008 dollars, the annualized costs are 

estimated at about ¥$90 million, which 

would approximately double the 

estimate of net cost savings of the 

proposed NSPS. As indicated by this 

difference, EPA has chosen a relatively 

conservative assumption (leading to an 

estimate of few savings and higher net 

costs) for the engineering costs analysis. 

The natural gas price at which the 

proposed NSPS breaks-even from an 

estimated engineering costs perspective 

is around $3.77/Mcf. A $1/Mcf change 

in the wellhead natural gas price leads 

to about a $180 million change in the 

annualized engineering costs of the 

proposed NSPS. Consequently, 

annualized engineering costs estimates 

would increase to about $140 million 

under a $3/Mcf price or decrease to 

about ¥$230 million under a $5/Mcf 

price. For further details on this 

sensitivity analysis, please refer the 

regulatory impact analysis (RIA) for this 

rulemaking located in the docket. 

H. What are the economic impacts? 

The NEMS analysis of energy system 

impacts for the proposed NSPS option 

estimates that domestic natural gas 

production is likely to increase slightly 

(about 20 billion cubic feet or 0.1 

percent) and average natural gas prices 

to decrease slightly ($0.04 per Mcf in 

2008 dollars or 0.9 percent at the 

wellhead for onshore producers in the 

lower 48 states) for 2015, the year of 

analysis. This increase in production 

and decrease in wellhead price is 

largely a result of the increased natural 

gas and condensate recovery as a result 

of complying with the NSPS. Domestic 

crude oil production is not expected to 

change, while average crude oil prices 

are estimated to decrease slightly 

($0.02/barrel in 2008 dollars or less than 

0.1 percent at the wellhead for onshore 

producers in the lower 48 states) in the 

year of analysis, 2015. The NEMS-based 

analysis estimates in the year of 

analysis, 2015, that net imports of 

natural gas and crude will not change 

significantly. 

Total CO2e emissions from energyrelated sources are expected to increase 

about 2.0 million metric tons CO2e or 

0.04 percent under the proposed NSPS, 

according to the NEMS analysis. This 

increase is attributable largely to natural 

gas consumption increases. This 

estimate does not include CO2e 

reductions from the implementation of 

the controls; these reductions are 

discussed in more detail in the benefits 

section that follows. 

We did not estimate the energy 

economy impacts of the proposed 

NESHAP amendments using NEMS, as 

the expected costs of the rule are not 

likely to have estimable impacts on the 

national energy economy. 

I. What are the benefits? 

The proposed Oil and Natural Gas 

NSPS and NESHAP amendments are 

expected to result in significant 

reductions in existing emissions and 

prevent new emissions from expansions 

of the industry. These proposed rules 

combined are anticipated to reduce 

38,000 tons of HAP, 540,000 tons of 

VOC and 3.4 million tons of methane. 

These pollutants are associated with 

substantial health effects, welfare effects 

and climate effects. With the data 

available, we are not able to provide 

credible health benefit estimates for the 

reduction in exposure to HAP, ozone 

and PM (2.5 microns and less) (PM2.5) 

for these rules, due to the differences in 

the locations of oil and natural gas 

emission points relative to existing 

information and the highly localized 

nature of air quality responses 

associated with HAP and VOC 

reductions. 

This is not to imply that there are no 

benefits of the rules; rather, it is a 

reflection of the difficulties in modeling 

the direct and indirect impacts of the 

reductions in emissions for this 

industrial sector with the data currently 

available. In addition to health 

improvements, there will be 

improvements in visibility effects, 

ecosystem effects and climate effects, as 

well as additional product recovery. 

Although we do not have sufficient 

information or modeling available to 

provide quantitative estimates for this 

rulemaking, we include a qualitative 

assessment of the health effects 

associated with exposure to HAP, ozone 

and PM2.5 in the RIA for this rule. These 

qualitative effects are briefly 

summarized below, but for more 

detailed information, please refer to the 

RIA, which is available in the docket. 

One of the HAP of concern from the oil 

and natural gas sector is benzene, which 

is a known human carcinogen, and 

formaldehyde, which is a probable 

human carcinogen. VOC emissions are 

precursors to both PM2.5 and ozone 

formation. As documented in previous 

analyses (U.S. EPA, 2006 41 and U.S. 

EPA, 2010 42), exposure to PM2.5 and 

ozone is associated with significant 

public health effects. PM2.5 is associated 

with health effects such as premature 

mortality for adults and infants, 

cardiovascular morbidity, such as heart 

attacks, hospital admissions and 

respiratory morbidity such as asthma 

attacks, acute and chronic bronchitis, 

hospital and emergency room visits, 

work loss days, restricted activity days 

and respiratory symptoms, as well as 

visibility impairment.43 Ozone is 

associated with health effects such as 

respiratory morbidity such as asthma 

attacks, hospital and emergency 

department visits, school loss days and 

premature mortality, as well as injury to 

vegetation and climate effects.44

In addition to the improvements in air 

quality and resulting benefits to human 

health and non-climate welfare effects 

previously discussed, this proposed rule 

is expected to result in significant 

climate co-benefits due to anticipated 

methane reductions. Methane is a 

potent GHG that, once emitted into the 

atmosphere, absorbs terrestrial infrared 

radiation, which contributes to 

increased global warming and 

continuing climate change. Methane 

reacts in the atmosphere to form ozone 

and ozone also impacts global 

temperatures. According to the 


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52792 Federal Register / Vol. 76, No. 163 / Tuesday, August 23, 2011 / Proposed Rules 

45U.S. EPA (2011), 2011 U.S. Greenhouse Gas 

Inventory Report Executive Summary available on 

the internet at http://www.epa.gov/ 

climateexchange/emissions/downloads11/US-GHGInventory-2011-Executive Summary.pdf. 

46U.S. EPA. Greenhouse Gas Equivalency 

Calculator available at: http://www.epa.gov/ 

cleanenergy/energy-resources/calculator.html 

accessed 07/19/11. 47 Interagency Working Group on Social Cost of 

Carbon (IWGSC). 2010. Technical Support 

Document: Social Cost of Carbon for Regulatory 

Impact Analysis Under Executive Order 12866. 

Docket ID EPA–HQ–OAR–2009–0472–114577. 

http://www.epa.gov/otaq/climate/regulations/scctsd.pdf; Accessed March 30, 2011. 

48U.S. EPA. Final Rulemaking: Light-Duty 

Vehicle Greenhouse Gas Emissions Standards and 

Corporate Average Fuel Economy Standards. May 

2010. Available on the Internet at http:// 

www.epa.gov/otaq/climate/regulations.htm#finalR. 

49 Interagency Working Group on Social Cost of 

Carbon (IWGSC). 2010. Technical Support 

Document: Social Cost of Carbon for Regulatory 

Impact Analysis Under Executive Order 12866. 

50Marten and Newbold (2011), Estimating the 

Social Cost of Non-CO2 GHG Emissions: Methane 

and Nitrous Oxide, NCEE Working Paper Series 

#11–01. http://yosemite.epa.gov/EE/epa/eed.nsf/

WPNumber/2011-01?OpenDocument. 

Intergovernmental Panel on Climate 

Change (IPCC) 4th Assessment Report 

(2007), methane is the second leading 

long-lived climate forcer after CO2

globally. Total methane emissions from 

the oil and gas industry represent about 

40 percent of the total methane 

emissions from all sources and account 

for about 5 percent of all CO2e 

emissions in the United States, with 

natural gas systems being the single 

largest contributor to United States 

anthropogenic methane emissions.45

Methane, in addition to other GHG 

emissions, contributes to warming of the 

atmosphere, which, over time, leads to 

increased air and ocean temperatures, 

changes in precipitation patterns, 

melting and thawing of global glaciers 

and ice, increasingly severe weather 

events, such as hurricanes of greater 

intensity and sea level rise, among other 

impacts. 

This rulemaking proposes emission 

control technologies and regulatory 

alternatives that will significantly 

decrease methane emissions from the oil 

and natural gas sector in the United 

States. The regulatory alternatives 

proposed for the NESHAP and the NSPS 

are expected to reduce methane 

emissions annually by about 3.4 million 

short tons or 65 million metric tons 

CO2e. After considering the secondary 

impacts of this proposal previously 

discussed, such as increased CO2

emissions from well completion 

combustion and decreased CO2e 

emissions because of fuel-switching by 

consumers, the methane reductions 

become about 62 million metric tons 

CO2e. These reductions represent about 

26 percent of the baseline methane 

emissions for this sector reported in the 

EPA’s U.S. Greenhouse Gas Inventory 

Report for 2009 (251.55 million metric 

tons CO2e when petroleum refineries 

and petroleum transportation are 

excluded because these sources are not 

examined in this proposal). After 

considering the secondary impacts of 

this proposal, such as increased CO2

emissions from well completion 

combustion and decreased CO2

emissions because of fuel-switching by 

consumers, the CO2e GHG reductions 

are reduced to about 62 million metric 

tons CO2e. However, it is important to 

note that the emission reductions are 

based upon predicted activities in 2015; 

the EPA did not forecast sector-level 

emissions in 2015 for this rulemaking. 

These emission reductions equate to the 

climate benefits of taking approximately 

11 million typical passenger cars off the 

road or eliminating electricity use from 

about 7 million typical homes each 

year.46

The EPA recognizes that the methane 

reductions proposed in this rule will 

provide for significant economic climate 

benefits to society just described. 

However, there is no interagencyaccepted methodology to place 

monetary values on these benefits. A 

‘global warming potential (GWP) 

approach’ of converting methane to 

CO2e using the GWP of methane 

provides an approximation method for 

estimating the monetized value of the 

methane reductions anticipated from 

this rule. This calculation uses the GWP 

of the non-CO2 gas to estimate CO2

equivalents and then multiplies these 

CO2 equivalent emission reductions by 

the social cost of carbon developed by 

the Interagency Social Cost of Carbon 

Work Group to generate monetized 

estimates of the benefits. 

The social cost of carbon is an 

estimate of the net present value of the 

flow of monetized damages from a 1- 

metric ton increase in CO2 emissions in 

a given year (or from the alternative 

perspective, the benefit to society of 

reducing CO2 emissions by 1 ton). For 

more information about the social cost 

of carbon, see the Support Document: 

Social Cost of Carbon for Regulatory 

Impact Analysis Under Executive Order 

12866 47 and RIA for the Light-Duty 

Vehicle GHG rule.48 Applying this 

approach to the methane reductions 

estimated for the proposed NESHAP 

and NSPS of the oil and gas rule, the 

2015 climate co-benefits vary by 

discount rate and range from about $370 

million to approximately $4.7 billion; 

the mean social cost of carbon at the 3- 

percent discount rate results in an 

estimate of about $1.6 billion in 2015. 

The ratio of domestic to global 

benefits of emission reductions varies 

with key parameter assumptions. For 

example, with a 2.5 or 3 percent 

discount rate, the U.S. benefit is about 

7–10 percent of the global benefit, on 

average, across the scenarios analyzed. 

Alternatively, if the fraction of GDP lost 

due to climate change is assumed to be 

similar across countries, the domestic 

benefit would be proportional to the 

U.S. share of global GDP, which is 

currently about 23 percent. On the basis 

of this evidence, values from 7 to 23 

percent should be used to adjust the 

global SCC to calculate domestic effects. 

It is recognized that these values are 

approximate, provisional and highly 

speculative. There is no a priori reason 

why domestic benefits should be a 

constant fraction of net global damages 

over time.49

These co-benefits equate to a range of 

approximately $110 to $1,400 per short 

ton of methane reduced, depending 

upon the discount rate assumed with a 

per ton estimate of $480 at the 3-percent 

discount rate. Methane climate cobenefit estimates for additional 

regulatory alternatives are included in 

the RIA for this proposed rule. These 

social cost of methane benefit estimates 

are not the same as would be derived 

from direct computations (using the 

integrated assessment models employed 

to develop the Interagency Social Cost 

of Carbon estimates) for a variety of 

reasons, including the shorter 

atmospheric lifetime of methane relative 

to CO2 (about 12 years compared to CO2

whose concentrations in the atmosphere 

decay on timescales of decades to 

millennia). The climate impacts also 

differ between the pollutants for reasons 

other than the radiative forcing profiles 

and atmospheric lifetimes of these 

gases. 

Methane is a precursor to ozone and 

ozone is a short-lived climate forcer that 

contributes to global warming. The use 

of the IPCC Second Assessment Report 

GWP to approximate co-benefits may 

underestimate the direct radiative 

forcing benefits of reduced ozone levels 

and does not capture any secondary 

climate co-benefits involved with 

ozone-ecosystem interactions. In 

addition, a recent EPA National Center 

of Environmental Economics working 

paper suggests that this quick ‘GWP 

approach’ to benefits estimation will 

likely understate the climate benefits of 

methane reductions in most cases.50

This conclusion is reached using the 

100-year GWP for methane of 25 as put 

forth in the IPCC Fourth Assessment 

Report (AR 4), as opposed to the lower 


emcdonald on DSK2BSOYB1PROD with PROPOSALS2
Federal Register / Vol. 76, No. 163 / Tuesday, August 23, 2011 / Proposed Rules 52793 

51Fann, N., C.M. Fulcher, B.J. Hubbell. The 

influence of location, source, and emission type in 

estimates of the human health benefits of reducing a ton of air pollution. Air Qual Atmos Health (2009) 

2:169–176. 

value of 21 used in this analysis. Using 

the higher GWP estimate of 25 would 

increase these reported methane climate 

co-benefit estimates by about 19 

percent. Although the IPCC Assessment 

Report (AR4) suggested a GWP of 25 for 

methane, the EPA has used GWP of 21 

to estimate the methane climate cobenefits for this oil and gas proposal in 

order to provide estimates more 

consistent with global GHG inventories, 

which currently use GWP from the IPCC 

Second Assessment Report. 

Due to the uncertainties involved 

with the ‘GWP approach’ estimates 

presented and methane climate cobenefits estimates available in the 

literature, the EPA chooses not to 

compare these co-benefit estimates to 

the costs of the rule for this proposal. 

Rather, the EPA presents the ‘GWP 

approach’ climate co-benefit estimates 

as an interim method to produce these 

estimates until the Interagency Social 

Cost of Carbon Work Group develops 

values for non-CO2 GHG. The EPA 

requests comments from interested 

parties and the public about this interim 

approach specifically and more broadly 

about appropriate methods to monetize 

the climate benefits of methane 

reductions. In particular, the EPA seeks 

public comments to this proposed 

rulemaking regarding social cost of 

methane estimates that may be used to 

value the co-benefits of methane 

emission reductions anticipated for the 

oil and gas industry from this rule. 

Comments specific to whether GWP is 

an acceptable method for generating a 

placeholder value for the social cost of 

methane until interagency-modeled 

estimates become available are 

welcome. Public comments may be 

provided in the official docket for this 

proposed rulemaking in accordance 

with the process outlined earlier in this 

notice. These comments will be 

considered in developing the final rule 

for this rulemaking. 

For the proposed NESHAP 

amendments, a break-even analysis 

suggests that HAP emissions would 

need to be valued at $12,000 per ton for 

the benefits to exceed the costs if the 

health, ecosystem and climate benefits 

from the reductions in VOC and 

methane emissions are assumed to be 

zero. Even though emission reductions 

of VOC and methane are co-benefits for 

the proposed NESHAP amendments, 

they are legitimate components of the 

total benefit-cost comparison. If we 

assume the health benefits from HAP 

emission reductions are zero, the VOC 

emissions would need to be valued at 

$1,700 per ton or the methane emissions 

would need to be valued at $3,300 per 

ton for the co-benefits to exceed the 

costs. All estimates are in 2008 dollars. 

For the proposed NSPS, the revenue 

from additional product recovery 

exceeds the costs, which renders a 

break-even analysis unnecessary when 

these revenues are included in the 

analysis. Based on the methodology 

from Fann, Fulcher, and Hubbell 

(2009),51 ranges of benefit-per-ton 

estimates for emissions of VOC indicate 

that on average in the United States, 

VOC emissions are valued from $1,200 

to $3,000 per ton as a PM2.5 precursor, 

but emission reductions in specific 

areas are valued from $280 to $7,000 per 

ton in 2008 dollars. As a result, even if 

VOC emissions from oil and natural gas 

operations result in monetized benefits 

that are substantially below the national 

average, there is a reasonable chance 

that the benefits of the rule would 

exceed the costs, especially if we were 

able to monetize all of the additional 

benefits associated with ozone 

formation, visibility, HAP and methane. 

IX. Request for Comments 

We are soliciting comments on all 

aspects of this proposed action. All 

comments received during the comment 

period will be considered. In addition to 

general comments on the proposed 

actions, we are also interested in any 

additional data that may help to reduce 

the uncertainties inherent in the risk 

assessments. We are specifically 

interested in receiving corrections to the 

datasets used for MACT analyses and 

risk modeling. Such data should include 

supporting documentation in sufficient 

detail to allow characterization of the 

quality and representativeness of the 

data or information. Please see the 

following section for more information 

on submitting data. 

X. Submitting Data Corrections 

The facility-specific data used in the 

source category risk analyses, facilitywide analyses and demographic 

analyses for each source category 

subject to this action are available for 

download on the RTR Web page at 

http://www.epa.gov/ttn/atw/rrisk/ 

rtrpg.html. These data files include 

detailed information for each HAP 

emissions release point at each facility 

included in the source category and all 

other HAP emissions sources at these 

facilities (facility-wide emissions 

sources). However, it is important to 

note that the source category risk 

analysis included only those emissions 

tagged with the MACT code associated 

with the source category subject to the 

risk analysis. 

If you believe the data are not 

representative or are inaccurate, please 

identify the data in question, provide 

your reason for concern and provide any 

‘‘improved’’ data that you have, if 

available. When you submit data, we 

request that you provide documentation 

of the basis for the revised values to 

support your suggested changes. To 

submit comments on the data 

downloaded from the RTR Web page, 

complete the following steps: 

1. Within this downloaded file, enter 

suggested revisions to the data fields 

appropriate for that information. The 

data fields that may be revised include 

the following: 

Data element Definition 

Control Measure ................................................................. Are control measures in place? (yes or no). 

Control Measure Comment ................................................ Select control measure from list provided and briefly describe the control measure. 

Delete ................................................................................. Indicate here if the facility or record should be deleted. 

Delete Comment ................................................................ Describes the reason for deletion. 

Emission Calculation Method Code for Revised Emissions.Code description of the method used to derive emissions. For example, CEM, material balance, stack test, etc. 

Emission Process Group ................................................... Enter the general type of emission process associated with the specified emission 

point. 

Fugitive Angle .................................................................... Enter release angle (clockwise from true North); orientation of the y-dimension relative to true North, measured positive for clockwise starting at 0 degrees (maximum 89 degrees). 

Fugitive Length ................................................................... Enter dimension of the source in the east-west (x-) direction, commonly referred to 

as length (ft). 


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52794 Federal Register / Vol. 76, No. 163 / Tuesday, August 23, 2011 / Proposed Rules 

Data element Definition 

Fugitive Width .................................................................... Enter dimension of the source in the north-south (y-) direction, commonly referred to 

as width (ft). 

Malfunction Emissions ....................................................... Enter total annual emissions due to malfunctions (TPY). 

Malfunction Emissions Max Hourly .................................... Enter maximum hourly malfunction emissions here (lb/hr). 

North American Datum ...................................................... Enter datum for latitude/longitude coordinates (NAD27 or NAD83); if left blank, 

NAD83 is assumed. 

Process Comment .............................................................. Enter general comments about process sources of emissions. 

REVISED Address ............................................................. Enter revised physical street address for MACT facility here. 

REVISED City .................................................................... Enter revised city name here. 

REVISED County Name .................................................... Enter revised county name here. 

REVISED Emission Release Point Type ........................... Enter revised Emission Release Point Type here. 

REVISED End Date ........................................................... Enter revised End Date here. 

REVISED Exit Gas Flow Rate ........................................... Enter revised Exit Gas Flowrate here (ft3/sec). 

REVISED Exit Gas Temperature ....................................... Enter revised Exit Gas Temperature here (OF). 

REVISED Exit Gas Velocity ............................................... Enter revised Exit Gas Velocity here (ft/sec). 

REVISED Facility Category Code ...................................... Enter revised Facility Category Code here, which indicates whether facility is a major 

or area source. 

REVISED Facility Name .................................................... Enter revised Facility Name here. 

REVISED Facility Registry Identifier .................................. Enter revised Facility Registry Identifier here, which is an ID assigned by the EPA 

Facility Registry System. 

REVISED HAP Emissions Performance Level Code ........ Enter revised HAP Emissions Performance Level here. 

REVISED Latitude .............................................................. Enter revised Latitude here (decimal degrees). 

REVISED Longitude ........................................................... Enter revised Longitude here (decimal degrees). 

REVISED MACT Code ...................................................... Enter revised MACT Code here. 

REVISED Pollutant Code ................................................... Enter revised Pollutant Code here. 

REVISED Routine Emissions ............................................ Enter revised routine emissions value here (TPY). 

REVISED SCC Code ......................................................... Enter revised SCC Code here. 

REVISED Stack Diameter .................................................. Enter revised Stack Diameter here (ft). 

REVISED Stack Height ...................................................... Enter revised Stack Height here (Ft). 

REVISED Start Date .......................................................... Enter revised Start Date here. 

REVISED State .................................................................. Enter revised state here. 

REVISED Tribal Code ........................................................ Enter revised Tribal Code here. 

REVISED Zip Code ............................................................ Enter revised Zip Code here. 

Shutdown Emissions .......................................................... Enter total annual emissions due to shutdown events (TPY). 

Shutdown Emissions Max Hourly ...................................... Enter maximum hourly shutdown emissions here (lb/hr). 

Stack Comment .................................................................. Enter general comments about emission release points. 

Startup Emissions .............................................................. Enter total annual emissions due to startup events (TPY). 

Startup Emissions Max Hourly ........................................... Enter maximum hourly startup emissions here (lb/hr). 

Year Closed ....................................................................... Enter date facility stopped operations. 

2. Fill in the commenter information 

fields for each suggested revision (i.e., 

commenter name, commenter 

organization, commenter e-mail address, 

commenter phone number and revision 

comments). 

3. Gather documentation for any 

suggested emissions revisions (e.g., 

performance test reports, material 

balance calculations, etc.). 

4. Send the entire downloaded file 

with suggested revisions in Microsoft®

Access format and all accompanying 

documentation to Docket ID Number 

EPA–HQ–OAR–2010–0505 (through one 

of the methods described in the 

ADDRESSES section of this preamble). To 

expedite review of the revisions, it 

would also be helpful if you submitted 

a copy of your revisions to the EPA 

directly at RTR@epa.gov in addition to 

submitting them to the docket. 

5. If you are providing comments on 

a facility with multiple source 

categories, you need only submit one 

file for that facility, which should 

contain all suggested changes for all 

source categories at that facility. We 

request that all data revision comments 

be submitted in the form of updated 

Microsoft® Access files, which are 

provided on the http://www.epa.gov/ttn/ 

atw/rrisk/rtrpg.html Web page. 

XI. Statutory and Executive Order 

Reviews 

A. Executive Order 12866: Regulatory 

Planning and Review and Executive 

Order 13563: Improving Regulation and 

Regulatory Review 

Under 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. Accordingly, the EPA 

submitted this action to OMB for review 

under Executive Order 12866 and 

Executive Order 13563 (76 FR 3821, 

January 21, 2011) and any changes made 

in response to OMB recommendations 

have been documented in the docket for 

this action. 

In addition, the EPA prepared a RIA 

of the potential costs and benefits 

associated with this action. The RIA 

available in the docket describes in 

detail the empirical basis for the EPA’s 

assumptions and characterizes the 

various sources of uncertainties 

affecting the estimates below. Table 8 

shows the results of the cost and 

benefits analysis for these proposed 

rules. For more information on the 

benefit and cost analysis, as well as 

details on the regulatory options 

considered, please refer to the RIA for 

this rulemaking, which is available in 

the docket. 


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Federal Register / Vol. 76, No. 163 / Tuesday, August 23, 2011 / Proposed Rules 52795 

TABLE 8—SUMMARY OF THE MONETIZED BENEFITS, COSTS AND NET BENEFITS FOR THE PROPOSED OIL AND NATURAL

GAS NSPS AND NEHSAP AMENDMENTS IN 2015 

[Millions of 2008$] 1

Proposed NSPS Proposed NESHAP 

amendments 

Proposed NSPS and 

NESHAP amendments 

combined 

Total Monetized Benefits 2 ............................................... N/A N/A N/A. 

Total Costs 3 .................................................................... ¥$45 million $16 million ¥$29 million. 

Net Benefits ..................................................................... N/A N/A N/A. 

Non-monetized Benefits 4 5 .............................................. 37,000 tons of HAP 1,400 tons of HAP 38,000 tons of HAP. 

540,000 tons of VOC 9,200 tons of VOC 540,000 tons of VOC. 

3.4 million tons of methane 4,900 tons of methane 3.4 million tons of methane. 

Health effects of HAP exposure. 

Health effects of PM2.5 and ozone exposure. 

Visibility impairment. 

Vegetation effects. 

Climate effects. 

1All estimates are for the implementation year (2015). 

2While we expect that these avoided emissions will result in improvements in air quality and reductions in health effects associated with HAP, 

ozone and PM, as well as climate effects associated with methane, we have determined that quantification of those benefits cannot be accomplished for this rule in a defensible way. This is not to imply that there are no benefits of the rules; rather, it is a reflection of the difficulties in 

modeling the direct and indirect impacts of the reductions in emissions for this industrial sector with the data currently available. 3The engineering compliance costs are annualized using a 7-percent discount rate. The negative cost for the proposed NSPS reflects the inclusion of revenues from additional natural gas and hydrocarbon condensate recovery that are estimated as a result of the proposed NSPS. 4For the NSPS, reduced exposure to HAP and climate effects are co-benefits. For the NESHAP, reduced VOC emissions, PM2.5 and ozone 

exposure, visibility and vegetation effects and climate effects are co-benefits. 5The specific control technologies for these proposed rules are anticipated to have minor secondary disbenefits. The net CO2-equivalent emission reductions are 93,000 metric tons for the NESHAP and 62 million metric tons for the NSPS. 

B. Paperwork Reduction Act 

The information collection 

requirements in this proposed action 

have been submitted for approval to 

OMB under the Paperwork Reduction 

Act, 44 U.S.C. 3501, et seq. The ICR 

document prepared by the EPA has been 

assigned EPA ICR Numbers 1716.07 (40 

CFR part 60, subpart OOOO), 1788.10 

(40 CFR part 63, subpart HH), 1789.07 

(40 CFR part 63, subpart HHH) and 

1086.10 (40 CFR part 60, subparts KKK 

and subpart LLL). 

The information to be collected for 

the proposed NSPS and the proposed 

NESHAP amendments 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. 

These proposed rules would require 

maintenance inspections of the control 

devices, but would not require any 

notifications or reports beyond those 

required by the General Provisions. The 

recordkeeping requirements require 

only the specific information needed to 

determine compliance. 

For sources subject to the proposed 

NSPS, burden changes associated with 

these amendments result from the 

respondents’ annual reporting and 

recordkeeping burden associated with 

this proposed rule for this collection 

(averaged over the first 3 years after the 

effective date of the standards). The 

burden is estimated to be 560,000 labor 

hours at a cost of $18 million per year. 

This includes the burden previously 

estimated for sources subject to 40 CFR 

part 60, subpart KKK (which is being 

incorporated into 40 CFR part 60, 

subpart OOOO). The average hours and 

cost per regulated entity subject to the 

NSPS for oil and natural gas production 

and natural gas transmissions and 

distribution facilities would be 110 

hours per response and $3,693 per 

response, based on an average of 1,459 

operators responding per year and 16 

responses per year. 

The estimated recordkeeping and 

reporting burden after the effective date 

of the proposed amendments is 

estimated for all affected major and area 

sources subject to the Oil and Natural 

Gas Production NESHAP to be 

approximately 63,000 labor hours per 

year at a cost of $2.1 million per year. 

For the Natural Gas Transmission and 

Storage NESHAP, the recordkeeping and 

reporting burden is estimated to be 

2,500 labor hours per year at a cost of 

$86,800 per year. This estimate includes 

the cost of reporting, including reading 

instructions and information gathering. 

Recordkeeping cost estimates include 

reading instructions, planning activities 

and conducting compliance monitoring. 

The average hours and cost per 

regulated entity subject to the Oil and 

Natural Gas Production NESHAP would 

be 72 hours per year and $2,500 per 

year, based on an average of 846 

facilities per year and three responses 

per facility. For the Natural Gas 

Transmission and Storage NESHAP, the 

average hours and cost per regulated 

entity would be 50 hours per year and 

$1,600 per year, based on an average of 

53 facilities per year and three 

responses per facility. 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. 

To comment on the Agency’s need for 

this information, the accuracy of the 

provided burden estimates and any 

suggested methods for minimizing 

respondent burden, the EPA has 

established a public docket for this rule, 

which includes this ICR, under Docket 

ID Number EPA–HQ–OAR–2010–0505. 

Submit any comments related to the ICR 

to the EPA and OMB. See the ADDRESSES

section at the beginning of this notice 

for where to submit comments to the 


emcdonald on DSK2BSOYB1PROD with PROPOSALS2
52796 Federal Register / Vol. 76, No. 163 / Tuesday, August 23, 2011 / Proposed Rules 

EPA. Send comments to OMB at the 

Office of Information and Regulatory 

Affairs, Office of Management and 

Budget, 725 17th Street, NW., 

Washington, DC 20503, Attention: Desk 

Office for the EPA. Since OMB is 

required to make a decision concerning 

the ICR between 30 and 60 days after 

August 23, 2011, a comment to OMB is 

best assured of having its full effect if 

OMB receives it by September 22, 2011. 

The final rule will respond to any OMB 

or public comments on the information 

collection requirements contained in 

this proposal. 

C. Regulatory Flexibility Act 

The Regulatory Flexibility Act 

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 (SISNOSE). 

Small entities include small businesses, 

small organizations, and small 

governmental jurisdictions. For 

purposes of assessing the impact of this 

rule on small entities, a small entity is 

defined as: (1) A small business whose 

parent company has no more than 500 

employees (or revenues of less than $7 

million for firms that transport natural 

gas via pipeline); (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-forprofit enterprise which is independently 

owned and operated and is not 

dominant in its field. 

Proposed NSPS 

After considering the economic 

impact of the proposed NSPS on small 

entities, I certify that this action will not 

have a SISNOSE. The EPA performed a 

screening analysis for impacts on a 

sample of expected affected small 

entities by comparing compliance costs 

to entity revenues. Based upon the 

analysis in the RIA, which is in the 

Docket, EPA concludes the number of 

impacted small businesses is unlikely to 

be sufficiently large to declare a 

SISNOSE. Our judgment in this 

determination is informed by the fact 

that many affected firms are expected to 

receive revenues from the additional 

natural gas and condensate recovery 

engendered by the implementation of 

the controls evaluated in this RIA. As 

much of the additional natural gas 

recovery is estimated to arise from 

completion-related activities, we expect 

the impact on well-related compliance 

costs to be significantly mitigated. This 

conclusion is enhanced because the 

returns to REC activities occur without 

a significant time lag between 

implementing the control and obtaining 

the recovered product, unlike many 

control options where the emissions 

reductions accumulate over long 

periods of time; the reduced emission 

completions and recompletions occur 

over a short span of time, during which 

the additional product recovery is also 

accomplished. 

Proposed NESHAP Amendments 

After considering the economic 

impact of the proposed NESHAP 

amendments on small entities, I certify 

that this action will not have a 

SISNOSE. Based upon the analysis in 

the RIA, which is in the Docket, we 

estimate that 62 of the 118 firms (53 

percent) that own potentially affected 

facilities are small entities. The EPA 

performed a screening analysis for 

impacts on all expected affected small 

entities by comparing compliance costs 

to entity revenues. Among the small 

firms, 52 of the 62 (84 percent) are likely 

to have impacts of less than 1 percent 

in terms of the ratio of annualized 

compliance costs to revenues. 

Meanwhile, 10 firms (16 percent) are 

likely to have impacts greater than 1 

percent. Four of these 10 firms are likely 

to have impacts greater than 3 percent. 

While these 10 firms might receive 

significant impacts from the proposed 

NESHAP amendments, they represent a 

very small slice of the oil and gas 

industry in its entirety, less than 0.2 

percent of the estimated 6,427 small 

firms in NAICS 211. Although this final 

rule will not impact a substantial 

number of small entities, the EPA, 

nonetheless, has tried to reduce the 

impact of this rule on small entities by 

setting the final emissions limits at the 

MACT floor, the least stringent level 

allowed by law. 

We continue to be interested in the 

potential impacts of the proposed rule 

on small entities and welcome 

comments on issues related to such 

impacts. 

D. Unfunded Mandates Reform Act 

This action contains no Federal 

mandates under the provisions of title II 

of the Unfunded Mandates Reform Act 

of 1995 (UMRA), 2 U.S.C. 1531–1538 for 

state, local or tribal governments or the 

private sector. This proposed rule does 

not contain a Federal mandate that may 

result in expenditures of $100 million or 

more for state, local and tribal 

governments, in the aggregate, or to the 

private sector in any one year. Thus, 

this proposed rule is not subject to the 

requirements of sections 202 or 205 of 

UMRA. This proposed rule is also not 

subject to the requirements of section 

203 of UMRA because it contains no 

regulatory requirements that might 

significantly or uniquely affect small 

governments. This action contains no 

requirements that apply to such 

governments nor does it impose 

obligations upon them. 

E. Executive Order 13132: Federalism 

This proposed rule 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. Thus, Executive 

Order 13132 does not apply to this 

proposed rule. In the spirit of Executive 

Order 13132 and consistent with the 

EPA policy to promote communications 

between the EPA and state and local 

governments, the EPA specifically 

solicits comment on this proposed rule 

from state and local officials. 

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 

effect 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. 

The EPA specifically solicits 

additional comment on this proposed 

action from tribal officials. 

G. Executive Order 13045: Protection of 

Children From Environmental Health 

Risks and Safety Risks 

This proposed rule is not subject to 

Executive Order 13045 (62 FR 19885, 

April 23, 1997) because the Agency does 

not believe the environmental health 

risks or safety risks addressed by this 

action present a disproportionate risk to 

children. This actions’ health and risk 

assessments are contained in section 

VII.C of this preamble. 

The public is invited to submit 

comments or identify peer-reviewed 

studies and data that assess effects of 

early life exposure to HAP from oil and 

natural gas sector activities. 


emcdonald on DSK2BSOYB1PROD with PROPOSALS2
Federal Register / Vol. 76, No. 163 / Tuesday, August 23, 2011 / Proposed Rules 52797 

H. Executive Order 13211: Actions 

Concerning Regulations That 

Significantly Affect Energy Supply, 

Distribution or Use 

Executive Order 13211, (66 FR 28,355, 

May 22, 2001), provides that agencies 

shall prepare and submit to the 

Administrator of the Office of 

Information and Regulatory Affairs, 

OMB, a Statement of Energy Effects for 

certain actions identified as significant 

energy actions. Section 4(b) of Executive 

Order 13211 defines ‘‘significant energy 

actions’’ as ‘‘any action by an agency 

(normally published in the Federal 

Register) that promulgates or is 

expected to lead to the promulgation of 

a final rule or regulation, including 

notices of inquiry, advance notices of 

proposed rulemaking, and notices of 

proposed rulemaking: (1)(i) That is a 

significant regulatory action under 

Executive Order 12866 or any successor 

order and (ii) is likely to have a 

significant adverse effect on the supply, 

distribution, or use of energy; or (2) that 

is designated by the Administrator of 

the Office of Information and Regulatory 

Affairs as a significant energy action.’’ 

The proposed rules will result in the 

addition of control equipment and 

monitoring systems for existing and new 

sources within the oil and natural gas 

industry. The proposed NESHAP 

amendments are unlikely to have a 

significant adverse effect on the supply, 

distribution or use of energy. As such, 

the proposed NESHAP amendments are 

not ‘‘significant energy actions’’ as 

defined in Executive Order 13211 (66 

FR 28355, May 22, 2001). 

The proposed NSPS is also unlikely to 

have a significant effect on the supply, 

distribution or use of energy. As such, 

the proposed NSPS is not a ‘‘significant 

energy action’’ as defined in Executive 

Order 13211 (66 FR 28355, May 22, 

2001). The basis for the determination is 

as follows. 

As discussed in the impacts section of 

the Preamble, we use the NEMS to 

estimate the impacts of the proposed 

NSPS on the United States energy 

system. The NEMS is a publically 

available model of the United States 

energy economy developed and 

maintained by the Energy Information 

Administration of the United States 

DOE and is used to produce the Annual 

Energy Outlook, a reference publication 

that provides detailed forecasts of the 

United States energy economy. 

Proposed emission controls for the 

NSPS capture VOC emissions that 

otherwise would be vented to the 

atmosphere. Since methane is coemitted with VOC, a large proportion of 

the averted methane emissions can be 

directed into natural gas production 

streams and sold. One pollution control 

requirement of the proposed NSPS also 

captures saleable condensates. The 

revenues from additional natural gas 

and condensate recovery are expected to 

offset the costs of implementing the 

proposed NSPS. 

The analysis of energy impacts for the 

proposed NSPS that includes the 

additional product recovery shows that 

domestic natural gas production is 

estimated to increase (20 billion cubic 

feet or 0.1 percent) and natural gas 

prices to decrease ($0.04/Mcf or 0.9 

percent at the wellhead for producers in 

the lower 48 states) in 2015, the year of 

analysis. Domestic crude oil production 

is not estimated to change, while crude 

oil prices are estimated to decrease 

slightly ($0.02/barrel or less than 0.1 

percent at the wellhead for producers in 

the lower 48 states) in 2015, the year of 

analysis. All prices are in 2008 dollars. 

Additionally, the NSPS establishes 

several performance standards that give 

regulated entities flexibility in 

determining how to best comply with 

the regulation. In an industry that is 

geographically and economically 

heterogeneous, this flexibility is an 

important factor in reducing regulatory 

burden. 

For more information on the 

estimated energy effects, please refer to 

the economic impact analysis for this 

proposed rule. The analysis is available 

in the RIA, which is in the public 

docket. 

I. National Technology Transfer and 

Advancement Act 

Section 12(d) of the National 

Technology Transfer and Advancement 

Act of 1995 (NTTAA), Public Law No. 

104–113 (15 U.S.C. 272 note) directs the 

EPA to use voluntary consensus 

standards (VCS) in its regulatory 

activities unless to do so would be 

inconsistent with applicable law or 

otherwise impractical. VCS are 

technical standards (e.g., materials 

specifications, test methods, sampling 

procedures, and business practices) that 

are developed or adopted by VCS 

bodies. NTTAA directs the EPA to 

provide Congress, through OMB, 

explanations when the Agency decides 

not to use available and applicable VCS. 

The proposed rule involves technical 

standards. Therefore, the requirements 

of the NTTAA apply to this action. We 

are proposing to revise 40 CFR part 63, 

subpart HH and 40 CFR part 63, subpart 

HHH to allow ANSI/ASME PTC 19.10– 

1981, Flue and Exhaust Gas Analyses 

(Part 10, Instruments and Apparatus) to 

be used in lieu of EPA Methods 3B, 6 

and 16A. This standard is available from 

the American Society of Mechanical 

Engineers (ASME), Three Park Avenue, 

New York, NY 10016–5990. Also, we 

are proposing to revise subpart HHH to 

allow ASTM D6420–99 (2004), Test 

Method for Determination of Gaseous 

Organic Compounds by Direct Interface 

Gas Chromatography/Mass 

Spectrometry, to be used in lieu of EPA 

Method 18. For a detailed discussion of 

this VCS, and its appropriateness as a 

substitute for Method 18, see the final 

Oil and Natural Gas Production 

NESHAP (Area Sources) (72 FR 36, 

January 3, 2007). 

As a result, the EPA is proposing 

ASTM D6420–99 (2004) for use in 40 

CFR part 63, subpart HHH. The EPA 

also proposes to allow Method 18 as an 

option in addition to ASTM D6420–99 

(2004). This would allow the continued 

use of gas chromatography 

configurations other than gas 

chromatography/mass spectrometry. 

The EPA welcomes comments on this 

aspect of the proposed rulemaking and, 

specifically, invites the public to 

identify potentially-applicable VCS and 

to explain why such standards should 

be used in this regulation. 

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 EJ. Its main 

provision directs Federal agencies, to 

the greatest extent practicable and 

permitted by law, to make EJ part of 

their mission by identifying and 

addressing, as appropriate, 

disproportionately high and adverse 

human health or environmental effects 

of their programs, policies and activities 

on minority populations and lowincome populations in the United 

States. 

The EPA has determined that this 

proposed rule will not have 

disproportionately high and adverse 

human health or environmental effects 

on minority or low-income populations 

because it increases the 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. 

To examine the potential for any EJ 

issues that might be associated with 

each source category, we evaluated the 

distributions of HAP-related cancer and 

noncancer risks across different social, 

demographic and economic groups 

within the populations living near the 

facilities where these source categories 


emcdonald on DSK2BSOYB1PROD with PROPOSALS2
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are located. The methods used to 

conduct demographic analyses for this 

rule are described in section VII.C of the 

preamble for this rule. The development 

of demographic analyses to inform the 

consideration of EJ issues in EPA 

rulemakings is an evolving science. The 

EPA offers the demographic analyses in 

this proposed rulemaking as examples 

of how such analyses might be 

developed to inform such consideration, 

and invites public comment on the 

approaches used and the interpretations 

made from the results, with the hope 

that this will support the refinement 

and improve utility of such analyses for 

future rulemakings. 

For the demographic analyses, we 

focused on the populations within 50 

km of any facility estimated to have 

exposures to HAP which result in 

cancer risks of 1-in-1 million or greater, 

or noncancer HI of 1 or greater (based 

on the emissions of the source category 

or the facility, respectively). We 

examined the distributions of those 

risks across various demographic 

groups, comparing the percentages of 

particular demographic groups to the 

total number of people in those 

demographic groups nationwide. The 

results, including other risk metrics, 

such as average risks for the exposed 

populations, are documented in source 

category-specific technical reports in the 

docket for both source categories 

covered in this proposal. 

As described in the preamble, our risk 

assessments demonstrate that the 

regulations for the oil and natural gas 

production and natural gas transmission 

and storage source categories, are 

associated with an acceptable level of 

risk and that the proposed additional 

requirements will provide an ample 

margin of safety to protect public health. 

Our analyses also show that, for these 

source categories, there is no potential 

for an adverse environmental effect or 

human health multi-pathway effects, 

and that acute and chronic noncancer 

health impacts are unlikely. The EPA 

has determined that, although there may 

be an existing disparity in HAP risks 

from these sources between some 

demographic groups, no demographic 

group is exposed to an unacceptable 

level of risk. 

List of Subjects 

40 CFR Part 60 

Environmental protection, Air 

pollution control, Reporting and 

recordkeeping requirements, Volatile 

organic compounds. 

40 CFR Part 63 

Environmental protection, Air 

pollution control, Reporting and 

recordkeeping requirements, Volatile 

organic compounds. 

Dated: July 28, 2011. 

Lisa P. Jackson, 

Administrator. 

For the reasons set out in the 

preamble, title 40, chapter I of the Code 

of Federal Regulations is proposed to be 

amended as follows: 

PART 60—[AMENDED] 

1. The authority citation for part 60 

continues to read as follows: 

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

2. Section 60.17 is amended by: 

a. Revising paragraph (a)(7); and 

b. Revising paragraphs (a)(91) and 

(a)(92) to read as follows: 

§ 60.17 Incorporations by reference. 

* * * * * 

(a) * * * 

(7) ASTM D86–78, 82, 90, 93, 95, 96, 

Distillation of Petroleum Products, IBR 

approved for §§ 60.562–2(d), 60.593(d), 

60.593a(d), 60.633(h) and 60.5401(h). 

* * * * * 

(91) ASTM E169–63, 77, 93, General 

Techniques of Ultraviolet Quantitative 

Analysis, IBR approved for 

§§ 60.485a(d)(1), 60.593(b)(2), 

60.593a(b)(2), 60.632(f) and 60.5400(f). 

(92) ASTM E260–73, 91, 96, General 

Gas Chromatography Procedures, IBR 

approved for §§ 60.485a(d)(1), 

60.593(b)(2), 60.593a(b)(2), 60.632(f), 

60.5400(f) and 60.5406(b). 

* * * * * 

Subpart KKK—Standards of 

Performance for Equipment Leaks of 

VOC From Onshore Natural Gas 

Processing Plants for Which 

Construction, Reconstruction, or 

Modification Commenced After 

January 20, 1984, and on or Before 

August 23, 2011 

3. The heading for Subpart KKK is 

revised to read as set out above. 

4. Section 60.630 is amended by 

revising paragraph (b) to read as follows: 

§ 60.630 Applicability and designation of 

affected facility. 

* * * * * 

(b) Any affected facility under 

paragraph (a) of this section that 

commences construction, 

reconstruction, or modification after 

January 20, 1984, and on or before 

August 23, 2011, is subject to the 

requirements of this subpart. 

* * * * * 

Subpart LLL—Standards of 

Performance for SO2 Emissions From 

Onshore Natural Gas Processing for 

Which Construction, Reconstruction, 

or Modification Commenced After 

January 20, 1984, and on or Before 

August 23, 2011 

5. The heading for Subpart LLL is 

revised to read as set out above. 

6. Section 60.640 is amended by 

revising paragraph (d) to read as 

follows: 

§ 60.640 Applicability and designation of 

affected facilities. 

* * * * * 

(d) The provisions of this subpart 

apply to each affected facility identified 

in paragraph (a) of this section which 

commences construction or 

modification after January 20, 1984, and 

on or before August 23, 2011. 

* * * * * 

7. Add subpart OOOO to part 60 to 

read as follows: 

Subpart OOOO—Standards of Performance 

for Crude Oil and Natural Gas Production, 

Transmission, and Distribution 

Sec. 

60.5360 What is the purpose of this 

subpart? 

60.5365 Am I subject to this subpart? 

60.5370 When must I comply with this 

subpart? 

60.5375 What standards apply to gas 

wellhead affected facilities? 

60.5380 What standards apply to 

centrifugal compressor affected 

facilities? 

60.5385 What standards apply to 

reciprocating compressor affected 

facilities? 

60.5390 What standards apply to pneumatic 

controller affected facilities? 

60.5395 What standards apply to storage 

vessel affected facilities? 

60.5400 What VOC standards apply to 

affected facilities at an onshore natural 

gas processing plant? 

60.5401 What are the exceptions to the VOC 

standards for affected facilities at 

onshore natural gas processing plants? 

60.5402 What are the alternative emission 

limitations for equipment leaks from 

onshore natural gas processing plants? 

60.5405 What standards apply to 

sweetening units at onshore natural gas 

processing plants? 

60.5406 What test methods and procedures 

must I use for my sweetening units 

affected facilities at onshore natural gas 

processing plants? 

60.5407 What are the requirements for 

monitoring of emissions and operations 

from my sweetening unit affected 

facilities at onshore natural gas 

processing plants? 

60.5408 What is an optional procedure for 

measuring hydrogen sulfide in acid gas— 

Tutwiler Procedure? 

60.5410 How do I demonstrate initial 

compliance with the standards for my 


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gas wellhead affected facility, my 

centrifugal compressor affected facility, 

my reciprocating compressor affected 

facility, my pneumatic controller 

affected facility, my storage vessel 

affected facility, and my affected 

facilities at onshore natural gas 

processing plants? 

60.5415 How do I demonstrate continuous 

compliance with the standards for my 

gas wellhead affected facility, my 

centrifugal compressor affected facility, 

my stationary reciprocating compressor 

affected facility, my pneumatic 

controller affected facility, my storage 

vessel affected facility, and my affected 

facilities at onshore natural gas 

processing plants? 

60.5420 What are my notification, 

reporting, and recordkeeping 

requirements? 

60.5421 What are my additional 

recordkeeping requirements for my 

affected facility subject to VOC 

requirements for onshore natural gas 

processing plants? 

60.5422 What are my additional reporting 

requirements for my affected facility 

subject to VOC requirements for onshore 

natural gas processing plants? 

60.5423 What additional recordkeeping and 

reporting requirements apply to my 

sweetening unit affected facilities at 

onshore natural gas processing plants? 

60.5425 What part of the General Provisions 

apply to me? 

60.5430 What definitions apply to this 

subpart? 

Table 1 to Subpart OOOO of Part 60— 

Required Minimum Initial SO2 Emission 

Reduction Efficiency (Zi) 

Table 2 to Subpart OOOO of Part 60— 

Required Minimum SO2 Emission 

Reduction Efficiency (Zc) 

Table 3 to Subpart OOOO of Part 60— 

Applicability of General Provisions to 

Subpart OOOO 

Subpart OOOO—Standards of 

Performance for Crude Oil and Natural 

Gas Production, Transmission, and 

Distribution 

§ 60.5360 What is the purpose of this 

subpart? 

This subpart establishes emission 

standards and compliance schedules for 

the control of volatile organic 

compounds (VOC) and sulfur dioxide 

(SO2) emissions from affected facilities 

that commenced construction, 

modification or reconstruction after 

August 23, 2011. 

§ 60.5365 Am I subject to this subpart? 

If you are the owner or operator of one 

or more of the affected facilities listed 

in paragraphs (a) through (g) of this 

section that commenced construction, 

modification, or reconstruction after 

August 23, 2011 your affected facility is 

subject to the applicable provisions of 

this subpart. For the purposes of this 

subpart, a well completion operation 

following hydraulic fracturing or 

refracturing that occurs at a gas 

wellhead facility that commenced 

construction, modification, or 

reconstruction on or before August 23, 

2011 is considered a modification of the 

gas wellhead facility, but does not affect 

other equipment, process units, storage 

vessels, or pneumatic devices located at 

the well site. 

(a) A gas wellhead affected facility, is 

a single natural gas well. 

(b) A centrifugal compressor affected 

facility, which is defined as a single 

centrifugal compressor located between 

the wellhead and the city gate (as 

defined in § 60.5430), except that a 

centrifugal compressor located at a well 

site (as defined in § 60.5430) is not an 

affected facility under this subpart. For 

the purposes of this subpart, your 

centrifugal compressor is considered to 

have commenced construction on the 

date the compressor is installed at the 

facility. 

(c) A reciprocating compressor 

affected facility, which is defined as a 

single reciprocating compressor located 

between the wellhead and the city gate 

(as defined in § 60.5430), except that a 

reciprocating compressor located at a 

well site (as defined in § 60.5430) is not 

an affected facility under this subpart. 

For the purposes of this subpart, your 

reciprocating compressor is considered 

to have commenced construction on the 

date the compressor is installed at the 

facility. 

(d) A pneumatic controller affected 

facility, which is defined as a single 

pneumatic controller. 

(e) A storage vessel affected facility, 

which is defined as a single storage 

vessel. 

(f) Compressors and equipment (as 

defined in § 60.5430) located at onshore 

natural gas processing plants. 

(1) Each compressor in VOC service or 

in wet gas service is an affected facility. 

(2) The group of all equipment, except 

compressors, within a process unit is an 

affected facility. 

(3) Addition or replacement of 

equipment, as defined in § 60.5430, for 

the purpose of process improvement 

that is accomplished without a capital 

expenditure shall not by itself be 

considered a modification under this 

subpart. 

(4) Equipment (as defined in 

§ 60.5430) associated with a compressor 

station, dehydration unit, sweetening 

unit, underground storage tank, field gas 

gathering system, or liquefied natural 

gas unit is covered by §§ 60.5400, 

60.5401, 60.5402, 60.5421 and 60.5422 

of this subpart if it is located at an 

onshore natural gas processing plant. 

Equipment (as defined in § 60.5430) not 

located at the onshore natural gas 

processing plant site is exempt from the 

provisions of §§ 60.5400, 60.5401, 

60.5402, 60.5421 and 60.5422 of this 

subpart. 

(5) Affected facilities located at 

onshore natural gas processing plants 

and described in paragraphs (f)(1) and 

(f)(2) of this section are exempt from 

this subpart if they are subject to and 

controlled according to subparts VVa, 

GGG or GGGa of this part. 

(g) Sweetening units located onshore 

that process natural gas produced from 

either onshore or offshore wells. 

(1) Each sweetening unit that 

processes natural gas is an affected 

facility; and 

(2) Each sweetening unit that 

processes natural gas followed by a 

sulfur recovery unit is an affected 

facility. 

(3) Facilities that have a design 

capacity less than 2 long tons per day 

(LT/D) of hydrogen sulfide (H2S) in the 

acid gas (expressed as sulfur) are 

required to comply with recordkeeping 

and reporting requirements specified in 

§ 60.5423(c) but are not required to 

comply with §§ 60.5405 through 

60.5407 and paragraphs 60.5410(g) and 

60.5415(g) of this subpart. 

(4) Sweetening facilities producing 

acid gas that is completely reinjected 

into oil-or-gas-bearing geologic strata or 

that is otherwise not released to the 

atmosphere are not subject to §§ 60.5405 

through 60.5407, and §§ 60.5410(g), 

60.5415(g), and § 60.5423 of this 

subpart. 

§ 60.5370 When must I comply with this 

subpart? 

(a) You must be in compliance with 

the standards of this subpart no later 

than the date of publication of the final 

rule in the Federal Register or upon 

startup, whichever is later. 

(b) The provisions for exemption from 

compliance during periods of startup, 

shutdown, and malfunctions provided 

for in 40 CFR 60.8(c) do not apply to 

this subpart. 

(c) You are exempt from the 

obligation to obtain a permit under 40 

CFR part 70 or 40 CFR part 71, provided 

you are not otherwise required by law 

to obtain a permit under 40 CFR 70.3(a) 

or 40 CFR 71.3(a). Notwithstanding the 

previous sentence, you must continue to 

comply with the provisions of this 

subpart. 

§ 60.5375 What standards apply to gas 

wellhead affected facilities? 

If you are the owner or operator of a 

gas wellhead affected facility, you must 

comply with paragraphs (a) through (g) 

of this section. 


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(a) Except as provided in paragraph (f) 

of this section, for each well completion 

operation with hydraulic fracturing, as 

defined in § 60.5430, you must control 

emissions by the operational procedures 

found in paragraphs (a)(1) through (a)(3) 

of this section. 

(1) You must minimize the emissions 

associated with venting of hydrocarbon 

fluids and gas over the duration of 

flowback by routing the recovered 

liquids into storage vessels and routing 

the recovered gas into a gas gathering 

line or collection system. 

(2) You must employ sand traps, surge 

vessels, separators, and tanks during 

flowback and cleanout operations to 

safely maximize resource recovery and 

minimize releases to the environment. 

All salable quality gas must be routed to 

the gas gathering line as soon as 

practicable. 

(3) You must capture and direct 

flowback emissions that cannot be 

directed to the gathering line to a 

completion combustion device, except 

in conditions that may result in a fire 

hazard or explosion. Completion 

combustion devices must be equipped 

with a reliable continuous ignition 

source over the duration of flowback. 

(b) You must maintain a log for each 

well completion operation at each gas 

wellhead affected facility. The log must 

be completed on a daily basis and must 

contain the records specified in 

§ 60.5420(c)(1)(iii). 

(c) You must demonstrate initial 

compliance with the standards that 

apply to gas wellhead affected facilities 

as required by § 60.5410. 

(d) You must demonstrate continuous 

compliance with the standards that 

apply to gas wellhead affected facilities 

as required by § 60.5415. 

(e) You must perform the required 

notification, recordkeeping, and 

reporting as required by § 60.5420. 

(f) For wells meeting the criteria for 

wildcat or delineation wells, each well 

completion operation with hydraulic 

fracturing at a gas wellhead affected 

facility must reduce emissions by using 

a completion combustion device 

meeting the requirements of paragraph 

(a)(3) of this section. You must also 

maintain records specified in 

§ 60.5420(c)(1)(iii) for wildcat or 

delineation wells. 

§ 60.5380 What standards apply to 

centrifugal compressor affected facilities? 

You must comply with the standards 

in paragraphs (a) through (d) of this 

section, as applicable for each 

centrifugal compressor affected facility. 

(a) You must equip each rotating 

compressor shaft with a dry seal system 

upon initial startup. 

(b) You must demonstrate initial 

compliance with the standards that 

apply to centrifugal compressor affected 

facilities as required by § 60.5410. 

(c) You must demonstrate continuous 

compliance with the standards that 

apply to centrifugal compressor affected 

facilities as required by § 60.5415. 

(d) You must perform the required 

notification, recordkeeping, and 

reporting as required by § 60.5420. 

§ 60.5385 What standards apply to 

reciprocating compressor affected 

facilities? 

You must comply with the standards 

in paragraphs (a) through (d) of this 

section for each reciprocating 

compressor affected facility. 

(a) You must replace the reciprocating 

compressor rod packing before the 

compressor has operated for 26,000 

hours. The number of hours of operation 

must be continuously monitored 

beginning upon initial startup of your 

reciprocating compressor affected 

facility, or the date of publication of the 

final rule in the Federal Register, or the 

date of the previous reciprocating 

compressor rod packing replacement, 

whichever is later. 

(b) You must demonstrate initial 

compliance with standards that apply to 

reciprocating compressor affected 

facilities as required by § 60.5410. 

(c) You must demonstrate continuous 

compliance with standards that apply to 

reciprocating compressor affected 

facilities as required by § 60.5415. 

(d) You must perform the required 

notification, recordkeeping, and 

reporting as required by § 60.5420. 

§ 60.5390 What standards apply to 

pneumatic controller affected facilities? 

For each pneumatic controller 

affected facility you must comply with 

the VOC standards, based on natural gas 

as a surrogate for VOC, in either 

paragraph (b) or (c) of this section, as 

applicable. Pneumatic controllers 

meeting the conditions in paragraph (a) 

are exempt from this requirement. 

(a) The requirements of paragraph (b) 

or (c) of this section are not required if 

you demonstrate, to the Administrator’s 

satisfaction, that the use of a high bleed 

device is predicated. The demonstration 

may include, but is not limited to, 

response time, safety and actuation. 

(b) Each pneumatic controller affected 

facility located at a natural gas 

processing plant (as defined in 

§ 60.5430) must have zero emissions of 

natural gas. 

(c) Each pneumatic controller affected 

facility not located at a natural gas 

processing plant (as defined in 

§ 60.5430) must have natural gas 

emissions no greater than 6 standard 

cubic feet per hour. 

(d) You must demonstrate initial 

compliance with standards that apply to 

pneumatic controller affected facilities 

as required by § 60.5410. 

(e) You must demonstrate continuous 

compliance with standards that apply to 

pneumatic controller affected facilities 

as required by § 60.5415. 

(f) You must perform the required 

notification, recordkeeping, and 

reporting as required by § 60.5420, 

except that you are not required to 

submit the notifications specified in 

§ 60.5420(a). 

§ 60.5395 What standards apply to storage 

vessel affected facilities? 

You must comply with the standards 

in paragraphs (a) through (e) of this 

section for each storage vessel affected 

facility. 

(a) You must comply with the 

standards for storage vessels specified in 

§ 63.766(b) and (c) of this chapter, 

except as specified in paragraph (b) of 

this section. Storage vessels that meet 

either one or both of the throughput 

conditions specified in paragraphs (a)(1) 

or (a)(2) of this section are not subject 

to the standards of this section. 

(1) The annual average condensate 

throughput is less than 1 barrel per day 

per storage vessel. 

(2) The annual average crude oil 

throughput is less than 20 barrels per 

day per storage vessel. 

(b) This standard does not apply to 

storage vessels already subject to and 

controlled in accordance with the 

requirements for storage vessels in 

§ 63.766(b)(1) or (2) of this chapter. 

(c) You must demonstrate initial 

compliance with standards that apply to 

storage vessel affected facilities as 

required by § 60.5410. 

(d) You must demonstrate continuous 

compliance with standards that apply to 

storage vessel affected facilities as 

required by § 60.5415. 

(e) You must perform the required 

notification, recordkeeping, and 

reporting as required by § 60.5420. 

§ 60.5400 What VOC standards apply to 

affected facilities at an onshore natural gas 

processing plant? 

This section applies to each 

compressor in VOC service or in wet gas 

service and the group of all equipment 

(as defined in § 60.5430), except 

compressors, within a process unit. 

(a) You must comply with the 

requirements of § 60.482–1a(a), (b), and 

(d), § 60.482–2a, and § 60.482–4a 

through 60.482–11a, except as provided 

in § 60.5401. 


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(b) You may elect to comply with the 

requirements of §§ 60.483–1a and 

60.483–2a, as an alternative. 

(c) You may apply to the 

Administrator for permission to use an 

alternative means of emission limitation 

that achieves a reduction in emissions 

of VOC at least equivalent to that 

achieved by the controls required in this 

subpart according to the requirements of 

§ 60.5402 of this subpart. 

(d) You must comply with the 

provisions of § 60.485a of this part 

except as provided in paragraph (f) of 

this section. 

(e) You must comply with the 

provisions of §§ 60.486a and 60.487a of 

this part except as provided in 

§§ 60.5401, 60.5421, and 60.5422 of this 

part. 

(f) You must use the following 

provision instead of § 60.485a(d)(1): 

Each piece of equipment is presumed to 

be in VOC service or in wet gas service 

unless an owner or operator 

demonstrates that the piece of 

equipment is not in VOC service or in 

wet gas service. For a piece of 

equipment to be considered not in VOC 

service, it must be determined that the 

VOC content can be reasonably 

expected never to exceed 10.0 percent 

by weight. For a piece of equipment to 

be considered in wet gas service, it must 

be determined that it contains or 

contacts the field gas before the 

extraction step in the process. For 

purposes of determining the percent 

VOC content of the process fluid that is 

contained in or contacts a piece of 

equipment, procedures that conform to 

the methods described in ASTM E169– 

63, 77, or 93, E168–67, 77, or 92, or 

E260–73, 91, or 96 (incorporated by 

reference as specified in § 60.17) must 

be used. 

§ 60.5401 What are the exceptions to the 

VOC standards for affected facilities at 

onshore natural gas processing plants? 

(a) You may comply with the 

following exceptions to the provisions 

of subpart VVa of this part. 

(b)(1) Each pressure relief device in 

gas/vapor service may be monitored 

quarterly and within 5 days after each 

pressure release to detect leaks by the 

methods specified in § 60.485a(b) except 

as provided in § 60.5400(c) and in 

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

§ 60.482–4a(a) through (c) of subpart 

VVa. 

(2) If an instrument reading of 5000 

ppm or greater is measured, a leak is 

detected. 

(3)(i) When a leak is detected, it must 

be repaired as soon as practicable, but 

no later than 15 calendar days after it is 

detected, except as provided in 

§ 60.482–9a. 

(ii) A first attempt at repair must be 

made no later than 5 calendar days after 

each leak is detected. 

(4)(i) Any pressure relief device that 

is located in a nonfractionating plant 

that is monitored only by non-plant 

personnel may be monitored after a 

pressure release the next time the 

monitoring personnel are on-site, 

instead of within 5 days as specified in 

paragraph (b)(1) of this section and 

§ 60.482–4a(b)(1) of subpart VVa. 

(ii) No pressure relief device 

described in paragraph (b)(4)(i) of this 

section must be allowed to operate for 

more than 30 days after a pressure 

release without monitoring. 

(c) Sampling connection systems are 

exempt from the requirements of 

§ 60.482–5a. 

(d) Pumps in light liquid service, 

valves in gas/vapor and light liquid 

service, and pressure relief devices in 

gas/vapor service that are located at a 

nonfractionating plant with a design 

capacity to process 283,200 standard 

cubic meters per day (scmd) (10 million 

standard cubic feet per day) or more of 

field gas are exempt from the routine 

monitoring requirements of §§ 60.482– 

2a(a)(1) and 60.482–7a(a), and 

paragraph (b)(1) of this section. 

(e) Pumps in light liquid service, 

valves in gas/vapor and light liquid 

service, and pressure relief devices in 

gas/vapor service within a process unit 

that is located in the Alaskan North 

Slope are exempt from the routine 

monitoring requirements of §§ 60.482– 

2a(a)(1), 60.482–7a(a), and paragraph 

(b)(1) of this section. 

(f) Flares used to comply with this 

subpart must comply with the 

requirements of § 60.18. 

(g) An owner or operator may use the 

following provisions instead of 

§ 60.485a(e): 

(1) Equipment is in heavy liquid 

service if the weight percent evaporated 

is 10 percent or less at 150 °C (302 °F) 

as determined by ASTM Method D86– 

78, 82, 90, 95, or 96 (incorporated by 

reference as specified in § 60.17). 

(2) Equipment is in light liquid 

service if the weight percent evaporated 

is greater than 10 percent at 150 °C (302 

°F) as determined by ASTM Method 

D86–78, 82, 90, 95, or 96 (incorporated 

by reference as specified in § 60.17). 

§ 60.5402 What are the alternative 

emission limitations for equipment leaks 

from onshore natural gas processing 

plants? 

(a) If, in the Administrator’s 

judgment, an alternative means of 

emission limitation will achieve a 

reduction in VOC emissions at least 

equivalent to the reduction in VOC 

emissions achieved under any design, 

equipment, work practice or operational 

standard, the Administrator will 

publish, in the Federal Register, a 

notice permitting the use of that 

alternative means for the purpose of 

compliance with that standard. The 

notice may condition permission on 

requirements related to the operation 

and maintenance of the alternative 

means. 

(b) Any notice under paragraph (a) of 

this section must be published only 

after notice and an opportunity for a 

public hearing. 

(c) The Administrator will consider 

applications under this section from 

either owners or operators of affected 

facilities, or manufacturers of control 

equipment. 

(d) The Administrator will treat 

applications under this section 

according to the following criteria, 

except in cases where the Administrator 

concludes that other criteria are 

appropriate: 

(1) The applicant must collect, verify 

and submit test data, covering a period 

of at least 12 months, necessary to 

support the finding in paragraph (a) of 

this section. 

(2) If the applicant is an owner or 

operator of an affected facility, the 

applicant must commit in writing to 

operate and maintain the alternative 

means so as to achieve a reduction in 

VOC emissions at least equivalent to the 

reduction in VOC emissions achieved 

under the design, equipment, work 

practice or operational standard. 

§ 60.5405 What standards apply to 

sweetening units at onshore natural gas 

processing plants? 

(a) During the initial performance test 

required by § 60.8(b), you must achieve 

at a minimum, an SO2 emission 

reduction efficiency (Zi) to be 

determined from Table 1 of this subpart 

based on the sulfur feed rate (X) and the 

sulfur content of the acid gas (Y) of the 

affected facility. 

(b) After demonstrating compliance 

with the provisions of paragraph (a) of 

this section, you must achieve at a 

minimum, an SO2 emission reduction 

efficiency (Zc) to be determined from 

Table 2 of this subpart based on the 

sulfur feed rate (X) and the sulfur 

content of the acid gas (Y) of the 

affected facility. 

60.5406 What test methods and 

procedures must I use for my sweetening 

units affected facilities at onshore natural 

gas processing plants? 

(a) In conducting the performance 

tests required in § 60.8, you must use 


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the test methods in Appendix A of this 

part or other methods and procedures as 

specified in this section, except as 

provided in paragraph § 60.8(b). 

(b) During a performance test required 

by § 60.8, you must determine the 

minimum required reduction 

efficiencies (Z) of SO2 emissions as 

required in § 60.5405(a) and (b) as 

follows: 

(1) The average sulfur feed rate (X) 

must be computed as follows: 

X ¥ KQag 

Where: 

X = average sulfur feed rate, Mg/D (LT/D). 

Qa = average volumetric flow rate of acid gas 

from sweetening unit, dscm/day (dscf/ 

day). 

Y = average H2S concentration in acid gas 

feed from sweetening unit, percent by 

volume, expressed as a decimal. 

K = (32 kg S/kg-mole) / ((24.04 dscm/kgmole) (1000 kg S/Mg)) 

= 1.331 × 10¥3 Mg/dscm, for metric units 

= (32 lb S/lb-mole) / ((385.36 dscf/lb-mole) 

(2240 lb S/long ton)) 

= 3.707 × 10¥5 long ton/dscf, for English 

units. 

(2) You must use the continuous 

readings from the process flowmeter to 

determine the average volumetric flow 

rate (Qa) in dscm/day (dscf/day) of the 

acid gas from the sweetening unit for 

each run. 

(3) You must use the Tutwiler 

procedure in § 60.5408 or a 

chromatographic procedure following 

ASTM E–260 (incorporated by 

reference—see § 60.17) to determine the 

H2S concentration in the acid gas feed 

from the sweetening unit (Y). At least 

one sample per hour (at equally spaced 

intervals) must be taken during each 

4-hour run. The arithmetic mean of all 

samples must be the average H2S 

concentration (Y) on a dry basis for the 

run. By multiplying the result from the 

Tutwiler procedure by 1.62 × 10¥3, the 

units gr/100 scf are converted to volume 

percent. 

(4) Using the information from 

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

section, Tables 1 and 2 of this subpart 

must be used to determine the required 

initial (Zi) and continuous (Zc) 

reduction efficiencies of SO2 emissions. 

(c) You must determine compliance 

with the SO2 standards in § 60.5405(a) 

or (b) as follows: 

(1) You must compute the emission 

reduction efficiency (R) achieved by the 

sulfur recovery technology for each run 

using the following equation: 

(2) You must use the level indicators 

or manual soundings to measure the 

liquid sulfur accumulation rate in the 

product storage tanks. You must use 

readings taken at the beginning and end 

of each run, the tank geometry, sulfur 

density at the storage temperature, and 

sample duration to determine the sulfur 

production rate (S) in kg/hr (lb/hr) for 

each run. 

(3) You must compute the emission 

rate of sulfur for each run as follows: 

Where: 

E = emission rate of sulfur per run, kg/hr. 

Ce = concentration of sulfur equivalent (SO2

+ reduced sulfur), g/dscm (lb/dscf). 

Qsd = volumetric flow rate of effluent gas, 

dscm/hr (dscf/hr). 

K1 = conversion factor, 1000 g/kg 

(7000 gr/lb). 

(4) The concentration (Ce) of sulfur 

equivalent must be the sum of the SO2

and TRS concentrations, after being 

converted to sulfur equivalents. For 

each run and each of the test methods 

specified in this paragraph (c) of this 

section, you must use a sampling time 

of at least 4 hours. You must use 

Method 1 of Appendix A to part 60 of 

this chapter to select the sampling site. 

The sampling point in the duct must be 

at the centroid of the cross-section if the 

area is less than 5 m2 (54 ft2) or at a 

point no closer to the walls than 

1 m (39 in) if the cross-sectional area is 

5 m2 or more, and the centroid is more 

than 1 m (39 in.) from the wall. 

(i) You must use Method 6 of 

Appendix A to part 60 of this chapter 

to determine the SO2 concentration. You 

must take eight samples of 20 minutes 

each at 30-minute intervals. The 

arithmetic average must be the 

concentration for the run. The 

concentration must be multiplied by 

0.5 × 10¥3 to convert the results to 

sulfur equivalent. 

(ii) You must use Method 15 of 

appendix A to part 60 of this chapter to 

determine the TRS concentration from 

reduction-type devices or where the 

oxygen content of the effluent gas is less 

than 1.0 percent by volume. The 

sampling rate must be at least 3 liters/ 

min (0.1 ft3/min) to insure minimum 

residence time in the sample line. You 

must take sixteen samples at 15-minute 

intervals. The arithmetic average of all 

the samples must be the concentration 

for the run. The concentration in ppm 

reduced sulfur as sulfur must be 

multiplied by 1.333 × 10¥3 to convert 

the results to sulfur equivalent. 

(iii) You must use Method 16A or 

Method 15 of appendix A to part 60 of 

this chapter to determine the reduced 

sulfur concentration from oxidationtype devices or where the oxygen 

content of the effluent gas is greater than 

1.0 percent by volume. You must take 

eight samples of 20 minutes each at 30- 

minute intervals. The arithmetic average 

must be the concentration for the run. 

The concentration in ppm reduced 

sulfur as sulfur must be multiplied by 

1.333 × 10¥3 to convert the results to 

sulfur equivalent. 

(iv) You must use Method 2 of 

appendix A to part 60 of this chapter to 

determine the volumetric flow rate of 

the effluent gas. A velocity traverse 

must be conducted at the beginning and 

end of each run. The arithmetic average 

of the two measurements must be used 

to calculate the volumetric flow rate 

(Qsd) for the run. For the determination 

of the effluent gas molecular weight, a 

single integrated sample over the 4-hour 

period may be taken and analyzed or 

grab samples at 1-hour intervals may be 

taken, analyzed, and averaged. For the 

moisture content, you must take two 

samples of at least 0.10 dscm (3.5 dscf) 

and 10 minutes at the beginning of the 

4-hour run and near the end of the time 

period. The arithmetic average of the 

two runs must be the moisture content 

for the run. 

§ 60.5407 What are the requirements for 

monitoring of emissions and operations 

from my sweetening unit affected facilities 

at onshore natural gas processing plants? 

(a) If your sweetening unit affected 

facility is located at an onshore natural 

gas processing plant and is subject to 

the provisions of § 60.5405(a) or (b) you 

must install, calibrate, maintain, and 

operate monitoring devices or perform 

measurements to determine the 

following operations information on a 

daily basis: 

(1) The accumulation of sulfur 

product over each 24-hour period. The 

monitoring method may incorporate the 

use of an instrument to measure and 

record the liquid sulfur production rate, 

or may be a procedure for measuring 

and recording the sulfur liquid levels in 

the storage tanks with a level indicator 

or by manual soundings, with 

subsequent calculation of the sulfur 

production rate based on the tank 

geometry, stored sulfur density, and 

elapsed time between readings. The 

method must be designed to be accurate 

within ± 2 percent of the 24-hour sulfur 

accumulation. 

(2) The H2S concentration in the acid 

gas from the sweetening unit for each 

24-hour period. At least one sample per 

24-hour period must be collected and 

analyzed using the equation specified in 

§ 60.5406(b)(1). The Administrator may 

require you to demonstrate that the H2S 

concentration obtained from one or 

more samples over a 24-hour period is 


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within ± 20 percent of the average of 12 

samples collected at equally spaced 

intervals during the 24-hour period. In 

instances where the H2S concentration 

of a single sample is not within ± 20 

percent of the average of the 12 equally 

spaced samples, the Administrator may 

require a more frequent sampling 

schedule. 

(3) The average acid gas flow rate 

from the sweetening unit. You must 

install and operate a monitoring device 

to continuously measure the flow rate of 

acid gas. The monitoring device reading 

must be recorded at least once per hour 

during each 24-hour period. The average 

acid gas flow rate must be computed 

from the individual readings. 

(4) The sulfur feed rate (X). For each 

24-hour period, you must compute X 

using the equation specified in 

§ 60.5406(b)(3). 

(5) The required sulfur dioxide 

emission reduction efficiency for the 

24-hour period. You must use the sulfur 

feed rate and the H2S concentration in 

the acid gas for the 24-hour period, as 

applicable, to determine the required 

reduction efficiency in accordance with 

the provisions of § 60.5405(b). 

(b) Where compliance is achieved 

through the use of an oxidation control 

system or a reduction control system 

followed by a continually operated 

incineration device, you must install, 

calibrate, maintain, and operate 

monitoring devices and continuous 

emission monitors as follows: 

(1) A continuous monitoring system to 

measure the total sulfur emission rate 

(E) of SO2 in the gases discharged to the 

atmosphere. The SO2 emission rate 

must be expressed in terms of 

equivalent sulfur mass flow rates (kg/hr 

(lb/hr)). The span of this monitoring 

system must be set so that the 

equivalent emission limit of 

§ 60.5405(b) will be between 30 percent 

and 70 percent of the measurement 

range of the instrument system. 

(2) Except as provided in paragraph 

(b)(3) of this section: A monitoring 

device to measure the temperature of 

the gas leaving the combustion zone of 

the incinerator, if compliance with 

§ 60.5405(a) is achieved through the use 

of an oxidation control system or a 

reduction control system followed by a 

continually operated incineration 

device. The monitoring device must be 

certified by the manufacturer to be 

accurate to within ± 1 percent of the 

temperature being measured. 

(3) When performance tests are 

conducted under the provision of § 60.8 

to demonstrate compliance with the 

standards under § 60.5405, the 

temperature of the gas leaving the 

incinerator combustion zone must be 

determined using the monitoring 

device. If the volumetric ratio of sulfur 

dioxide to sulfur dioxide plus total 

reduced sulfur (expressed as SO2) in the 

gas leaving the incinerator is equal to or 

less than 0.98, then temperature 

monitoring may be used to demonstrate 

that sulfur dioxide emission monitoring 

is sufficient to determine total sulfur 

emissions. At all times during the 

operation of the facility, you must 

maintain the average temperature of the 

gas leaving the combustion zone of the 

incinerator at or above the appropriate 

level determined during the most recent 

performance test to ensure the sulfur 

compound oxidation criteria are met. 

Operation at lower average temperatures 

may be considered by the Administrator 

to be unacceptable operation and 

maintenance of the affected facility. You 

may request that the minimum 

incinerator temperature be reestablished 

by conducting new performance tests 

under § 60.8. 

(4) Upon promulgation of a 

performance specification of continuous 

monitoring systems for total reduced 

sulfur compounds at sulfur recovery 

plants, you may, as an alternative to 

paragraph (b)(2) of this section, install, 

calibrate, maintain, and operate a 

continuous emission monitoring system 

for total reduced sulfur compounds as 

required in paragraph (d) of this section 

in addition to a sulfur dioxide emission 

monitoring system. The sum of the 

equivalent sulfur mass emission rates 

from the two monitoring systems must 

be used to compute the total sulfur 

emission rate (E). 

(c) Where compliance is achieved 

through the use of a reduction control 

system not followed by a continually 

operated incineration device, you must 

install, calibrate, maintain, and operate 

a continuous monitoring system to 

measure the emission rate of reduced 

sulfur compounds as SO2 equivalent in 

the gases discharged to the atmosphere. 

The SO2 equivalent compound emission 

rate must be expressed in terms of 

equivalent sulfur mass flow rates (kg/hr 

(lb/hr)). The span of this monitoring 

system must be set so that the 

equivalent emission limit of 

§ 60.5405(b) will be between 30 and 70 

percent of the measurement range of the 

system. This requirement becomes 

effective upon promulgation of a 

performance specification for 

continuous monitoring systems for total 

reduced sulfur compounds at sulfur 

recovery plants. 

(d) For those sources required to 

comply with paragraph (b) or (c) of this 

section, you must calculate the average 

sulfur emission reduction efficiency 

achieved (R) for each 24-hour clock 

internal. The 24-hour interval may begin 

and end at any selected clock time, but 

must be consistent. You must compute 

the 24-hour average reduction efficiency 

(R) based on the 24-hour average sulfur 

production rate (S) and sulfur emission 

rate (E), using the equation in 

§ 60.5406(c)(1). 

(1) You must use data obtained from 

the sulfur production rate monitoring 

device specified in paragraph (a) of this 

section to determine S. 

(2) You must use data obtained from 

the sulfur emission rate monitoring 

systems specified in paragraphs (b) or 

(c) of this section to calculate a 24-hour 

average for the sulfur emission rate (E). 

The monitoring system must provide at 

least one data point in each successive 

15-minute interval. You must use at 

least two data points to calculate each 

1-hour average. You must use a 

minimum of 18 1-hour averages to 

compute each 24-hour average. 

(e) In lieu of complying with 

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

those sources with a design capacity of 

less than 152 Mg/D (150 LT/D) of H2S 

expressed as sulfur may calculate the 

sulfur emission reduction efficiency 

achieved for each 24-hour period by: 

Where: 

R = The sulfur dioxide removal efficiency 

achieved during the 24-hour period, 

percent. 

K2 = Conversion factor, 0.02400 Mg/D per kg/ 

hr (0.01071 LT/D per lb/hr). 

S = The sulfur production rate during the 24- 

hour period, kg/hr (lb/hr). 

X = The sulfur feed rate in the acid gas, Mg/ 

D (LT/D). 

(f) The monitoring devices required in 

paragraphs (b)(1), (b)(3) and (c) of this 

section must be calibrated at least 

annually according to the 

manufacturer’s specifications, as 

required by § 60.13(b). 

(g) The continuous emission 

monitoring systems required in 

paragraphs (b)(1), (b)(3), and (c) of this 

section must be subject to the emission 

monitoring requirements of § 60.13 of 

the General Provisions. For conducting 

the continuous emission monitoring 

system performance evaluation required 

by § 60.13(c), Performance Specification 

2 of appendix B to part 60 of this 

chapter must apply, and Method 6 must 

be used for systems required by 

paragraph (b) of this section. 


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1 Gas Engineers Handbook, Fuel Gas Engineering 

practices, The Industrial Press, 93 Worth Street, 

New York, NY, 1966, First Edition, Second Printing, 

page 6/25 (Docket A–80–20–A, Entry II–I–67). 

§ 60.5408 What is an optional procedure 

for measuring hydrogen sulfide in acid 

gas—Tutwiler Procedure? 1

(a) When an instantaneous sample is 

desired and H2S concentration is ten 

grains per 1000 cubic foot or more, a 

100 ml Tutwiler burette is used. For 

concentrations less than ten grains, a 

500 ml Tutwiler burette and more dilute 

solutions are used. In principle, this 

method consists of titrating hydrogen 

sulfide in a gas sample directly with a 

standard solution of iodine. 

(b) Apparatus. (See Figure 1 of this 

subpart) A 100 or 500 ml capacity 

Tutwiler burette, with two-way glass 

stopcock at bottom and three-way 

stopcock at top which connect either 

with inlet tubulature or glass-stoppered 

cylinder, 10 ml capacity, graduated in 

0.1 ml subdivision; rubber tubing 

connecting burette with leveling bottle. 

(c) Reagents. (1) Iodine stock solution, 

0.1N. Weight 12.7 g iodine, and 20 to 25 

g cp potassium iodide for each liter of 

solution. Dissolve KI in as little water as 

necessary; dissolve iodine in 

concentrated KI solution, make up to 

proper volume, and store in glassstoppered brown glass bottle. 

(2) Standard iodine solution, 1 ml = 

0.001771 g I. Transfer 33.7 ml of above 

0.1N stock solution into a 250 ml 

volumetric flask; add water to mark and 

mix well. Then, for 100 ml sample of 

gas, 1 ml of standard iodine solution is 

equivalent to 100 grains H2S per cubic 

feet of gas. 

(3) Starch solution. Rub into a thin 

paste about one teaspoonful of wheat 

starch with a little water; pour into 

about a pint of boiling water; stir; let 

cool and decant off clear solution. Make 

fresh solution every few days. 

(d) Procedure. Fill leveling bulb with 

starch solution. Raise (L), open cock (G), 

open (F) to (A), and close (F) when 

solutions starts to run out of gas inlet. 

Close (G). Purge gas sampling line and 

connect with (A). Lower (L) and open 

(F) and (G). When liquid level is several 

ml past the 100 ml mark, close (G) and 

(F), and disconnect sampling tube. Open 

(G) and bring starch solution to 100 ml 

mark by raising (L); then close (G). Open 

(F) momentarily, to bring gas in burette 

to atmospheric pressure, and close (F). 

Open (G), bring liquid level down to 10 

ml mark by lowering (L). Close (G), 

clamp rubber tubing near (E) and 

disconnect it from burette. Rinse 

graduated cylinder with a standard 

iodine solution (0.00171 g I per ml); fill 

cylinder and record reading. Introduce 

successive small amounts of iodine thru 

(F); shake well after each addition; 

continue until a faint permanent blue 

color is obtained. Record reading; 

subtract from previous reading, and call 

difference D. 

(e) With every fresh stock of starch 

solution perform a blank test as follows: 

Introduce fresh starch solution into 

burette up to 100 ml mark. Close (F) and 

(G). Lower (L) and open (G). When 

liquid level reaches the 10 ml mark, 

close (G). With air in burette, titrate as 

during a test and up to same end point. 

Call ml of iodine used C. Then, 

Grains H2S per 100 cubic foot of gas = 

100 (D¥C) 

(f) Greater sensitivity can be attained 

if a 500 ml capacity Tutwiler burette is 

used with a more dilute (0.001N) iodine 

solution. Concentrations less than 1.0 

grains per 100 cubic foot can be 

determined in this way. Usually, the 

starch-iodine end point is much less 

distinct, and a blank determination of 

end point, with H2S-free gas or air, is 

required. 

BILLING CODE 6560–50–P 


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BILLING CODE 6560–50–C 

§ 60.5410 How do I demonstrate initial 

compliance with the standards for my gas 

wellhead affected facility, my centrifugal 

compressor affected facility, my 

reciprocating compressor affected facility, 

my pneumatic controller affected facility, 

my storage vessel affected facility, and my 

affected facilities at onshore natural gas 

processing plants? 

You must determine initial 

compliance with the standards for each 

affected facility using the requirements 

in paragraphs (a) through (g) of this 

section. The initial compliance period 

begins on the date of publication of the 

final rule in the Federal Register or 

upon initial startup, whichever is later, 

and ends on the date the first annual 

report is due as specified in 

§ 60.5420(b). 

(a) You have achieved initial 

compliance with standards for each well 

completion operation conducted at your 

gas wellhead affected facility if you 

have complied with paragraphs (a)(1) 

and (a)(2) of this section. 

(1) You have notified the 

Administrator within 30 days of the 

commencement of the well completion 

operation, the date of the 

commencement of the well completion 

operation, the latitude and longitude 

coordinates of the well in decimal 

degrees to an accuracy and precision of 

five (5) decimals of a degree using the 

North American Datum (NAD) of 1983. 

(2) You have maintained a log of 

records as specified in § 60.5375(b) or (f) 

for each well completion operation 

conducted during the initial compliance 

period. 


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(3) You have submitted the initial 

annual report for your wellhead affected 

facility as required in § 60.5420(b). 

(b) You have achieved initial 

compliance with standards for your 

centrifugal compressor affected facility 

if the centrifugal compressor is fitted 

with a dry seal system upon initial 

startup as required by § 60.5380. 

(c) You have achieved initial 

compliance with standards for each 

reciprocating compressor affected 

facility if you have complied with 

paragraphs (c)(1) and (c)(2) of this 

section. 

(1) During the initial compliance 

period, you have continuously 

monitored the number of hours of 

operation. 

(2) You have included the cumulative 

number of hours of operation for your 

reciprocating compressor affected 

facility during the initial compliance 

period in your initial annual report 

required in § 60.5420(b). 

(d) You have achieved initial 

compliance with emission standards for 

your pneumatic controller affected 

facility if you comply with the 

requirements specified in paragraphs 

(d)(1) through (d)(4) of this section. 

(1) You have demonstrated, to the 

Administrator’s satisfaction, the use of a 

high bleed device is predicated as 

specified in § 60.5490(a). 

(2) You own or operate a pneumatic 

controller affected facility located at a 

natural gas processing plant and your 

pneumatic controller is driven other 

than by use of natural gas and therefore 

emits zero natural gas. 

(3) You own or operate a pneumatic 

controller affected facility not located at 

a natural gas processing plant and the 

manufacturer’s design specifications 

guarantee the controller emits less than 

or equal to 6.0 standard cubic feet of gas 

per hour. 

(4) You have included the information 

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

this section in the initial annual report 

submitted for your pneumatic controller 

affected facilities according to the 

requirements of § 60.5420(b). 

(e) You have demonstrated initial 

compliance with emission standards for 

your storage vessel affected facility if 

you are complying with paragraphs 

(e)(1) through (e)(7) of this section. 

(1) You have equipped the storage 

vessel with a closed vent system that 

meets the requirements of § 63.771(c) of 

this chapter connected to a control 

device that meets the conditions 

specified in § 63.771(d). 

(2) You have conducted an initial 

performance test as required in 

§ 63.772(e) of this chapter within 180 

days after initial startup or the date of 

publication of the final rule in the 

Federal Register and have conducted 

the compliance demonstration in 

§ 63.772(f). 

(3) You have conducted the initial 

inspections required in § 63.773(c) of 

this chapter. 

(4) You have installed and operated 

continuous parameter monitoring 

systems in accordance with § 63.773(d) 

of this chapter. 

(5) If you are exempt from the 

standards of § 60.5395 according to 

§ 60.5395(a)(1) or (a)(2), you have 

determined the condensate or crude oil 

throughput, as applicable, according to 

paragraphs (e)(5)(i) or (e)(5)(ii) of this 

section and demonstrated to the 

Administrator’s satisfaction that your 

annual average condensate throughput 

is less than 1 barrel per day per tank and 

your annual average crude oil 

throughput is less than 20 barrels per 

day per tank. 

(i) You have installed and operated a 

flow meter to measure condensate or 

crude oil throughput in accordance with 

the manufacturer’s procedures or 

specifications. 

(ii) You have used any other method 

approved by the Administrator to 

determine annual average condensate or 

crude oil throughput. 

(6) You have submitted the 

information in paragraphs (e)(1) through 

(e)(5) of this section in the initial annual 

report for your storage vessel affected 

facility as required in § 60.5420(b). 

(f) For affected facilities at onshore 

natural gas processing plants, initial 

compliance with the VOC requirements 

is demonstrated if you are in 

compliance with the requirements of 

§ 60.5400. 

(g) For sweetening unit affected 

facilities at onshore natural gas 

processing plants, initial compliance is 

demonstrated according to paragraphs 

(g)(1) through (g)(3) of this section. 

(1) To determine compliance with the 

standards for SO2 specified in 

§ 60.5405(a), during the initial 

performance test as required by § 60.8, 

the minimum required sulfur dioxide 

emission reduction efficiency (Zi) is 

compared to the emission reduction 

efficiency (R) achieved by the sulfur 

recovery technology as specified in 

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

section. 

(i) If R ≥ Zi, your affected facility is 

in compliance. 

(ii) If R < Zi, your affected facility is 

not in compliance. 

(2) The emission reduction efficiency 

(R) achieved by the sulfur reduction 

technology must be determined using 

the procedures in § 60.5406(c)(1). 

(3) You have submitted the results of 

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

section in the initial annual report 

submitted for your sweetening unit 

affected facilities at onshore natural gas 

processing plants. 

§ 60.5415 How do I demonstrate 

continuous compliance with the standards 

for my gas wellhead affected facility, my 

centrifugal compressor affected facility, my 

stationary reciprocating compressor 

affected facility, my pneumatic controller 

affected facility, my storage vessel affected 

facility, and my affected facilities at onshore 

natural gas processing plants? 

(a) For each gas wellhead affected 

facility, you must demonstrate 

continuous compliance by maintaining 

the records for each completion 

operation (as defined in § 60.5430) 

specified in § 60.5420. 

(b) For each centrifugal compressor 

affected facility, continuous compliance 

is demonstrated if the rotating 

compressor shaft is equipped with a dry 

seal. 

(c) For each reciprocating compressor 

affected facility, you have demonstrated 

continuous compliance according to 

paragraphs (c)(1) and (2) of this section 

(1) You have continuously monitored 

the number of hours of operation for 

each reciprocating compressor affected 

facility since initial startup, or the date 

of publication of the final rule in the 

Federal Register, or the date of the 

previous reciprocating compressor rod 

packing replacement, whichever is later. 

The cumulative number of hours of 

operation must be included in the 

annual report as required in 

§ 60.5420(b)(4). 

(2) You have replaced the 

reciprocating compressor rod packing 

before the total number of hours of 

operation reaches 26,000 hours. 

(d) For each pneumatic controller 

affected facility, continuous compliance 

is demonstrated by maintaining the 

records demonstrating that you have 

installed and operated the pneumatic 

controllers as required in § 60.5390(a), 

(b) or (c). 

(e) For each storage vessel affected 

facility, continuous compliance is 

demonstrated according to § 63.772(f) of 

this chapter. 

(f) For affected facilities at onshore 

natural gas processing plants, 

continuous compliance with VOC 

requirements is demonstrated if you are 

in compliance with the requirements of 

§ 60.5400. 

(g) For each sweetening unit affected 

facility at onshore natural gas 

processing plants, you must 

demonstrate continuous compliance 

with the standards for SO2 specified in 


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§ 60.5405(b) according to paragraphs 

(g)(1) and (g)(2) of this section. 

(1) The minimum required SO2

emission reduction efficiency (Zc) is 

compared to the emission reduction 

efficiency (R) achieved by the sulfur 

recovery technology. 

(i) If R ≥ Zc, your affected facility is 

in compliance. 

(ii) If R < Zc, your affected facility is 

not in compliance. 

(2) The emission reduction efficiency 

(R) achieved by the sulfur reduction 

technology must be determined using 

the procedures in § 60.5406(c)(1). 

(h) Affirmative defense for 

exceedance of emission limit during 

malfunction. In response to an action to 

enforce the standards set forth in 

§§ 60.5375, 60.5380, 60.5385, 60.5390, 

60.5395, 60.5400, and 60.5405, you may 

assert an affirmative defense to a claim 

for civil penalties for exceedances of 

such standards that are caused by 

malfunction, as defined at § 60.2. 

Appropriate penalties may be assessed, 

however, if you fail to meet your burden 

of proving all of the requirements in the 

affirmative defense. The affirmative 

defense shall not be available for claims 

for injunctive relief. 

(1) To establish the affirmative 

defense in any action to enforce such a 

limit, you must timely meet the 

notification requirements in 

§ 60.5420(a), and must prove by a 

preponderance of evidence that: 

(i) The excess emissions: 

(A) Were caused by a sudden, 

infrequent, and unavoidable failure of 

air pollution control and monitoring 

equipment, process equipment, or a 

process to operate in a normal or usual 

manner, and 

(B) Could not have been prevented 

through careful planning, proper design 

or better operation and maintenance 

practices; and 

(C) Did not stem from any activity or 

event that could have been foreseen and 

avoided, or planned for; and 

(D) Were not part of a recurring 

pattern indicative of inadequate design, 

operation, or maintenance; and 

(ii) Repairs were made as 

expeditiously as possible when the 

applicable emission limitations were 

being exceeded. Off-shift and overtime 

labor were used, to the extent 

practicable to make these repairs; and 

(iii) The frequency, amount and 

duration of the excess emissions 

(including any bypass) were minimized 

to the maximum extent practicable 

during periods of such emissions; and 

(iv) If the excess emissions 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 

(v) All possible steps were taken to 

minimize the impact of the excess 

emissions on ambient air quality, the 

environment and human health; and 

(vi) All emissions monitoring and 

control systems were kept in operation 

if at all possible, consistent with safety 

and good air pollution control practices; 

and 

(vii) All of the actions in response to 

the excess emissions were documented 

by properly signed, contemporaneous 

operating logs; and 

(viii) At all times, the facility was 

operated in a manner consistent with 

good practices for minimizing 

emissions; and 

(ix) 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 excess emissions resulting from the 

malfunction event at issue. The analysis 

shall also specify, using best monitoring 

methods and engineering judgment, the 

amount of excess emissions that were 

the result of the malfunction. 

(2) The owner or operator of the 

facility experiencing an exceedance of 

its emission limit(s) during a 

malfunction shall notify the 

Administrator by telephone or facsimile 

(FAX) transmission as soon as possible, 

but no later than 2 business days after 

the initial occurrence of the 

malfunction, if it wishes to avail itself 

of an affirmative defense to civil 

penalties for that malfunction. The 

owner or operator seeking to assert an 

affirmative defense shall also submit a 

written report to the Administrator 

within 45 days of the initial occurrence 

of the exceedance of the standards in 

§§ 60.5375, 60.5380, 60.5385, 60.5390, 

60.5395, and 60.5400 to demonstrate, 

with all necessary supporting 

documentation, that it has met the 

requirements set forth in paragraph (a) 

of this section. The owner or operator 

may seek an extension of this deadline 

for up to 30 additional days by 

submitting a written request to the 

Administrator before the expiration of 

the 45-day period. Until a request for an 

extension has been approved by the 

Administrator, the owner or operator is 

subject to the requirement to submit 

such report within 45 days of the initial 

occurrence of the exceedance. 

§ 60.5420 What are my notification, 

reporting, and recordkeeping 

requirements? 

(a) You must submit the notifications 

required in § 60.7(a)(1), (a)(3) and (a)(4), 

and according to paragraphs (a)(1) and 

(a)(2) of this section, if you own or 

operate one or more of the affected 

facilities specified in § 60.5365. For the 

purposes of this subpart, a workover 

that occurs after August 23, 2011 at each 

affected facility for which construction, 

reconstruction, or modification 

commenced on or before August 23, 

2011 is considered a modification for 

which a notification must be submitted 

under § 60.7(a)(4). 

(1) If you own or operate a pneumatic 

controller affected facility you are not 

required to submit the notifications 

required in § 60.7(a)(1), (a)(3) and (a)(4). 

(2) If you own or operate a gas 

wellhead affected facility, you must 

submit a notification to the 

Administrator within 30 days of the 

commencement of the well completion 

operation. The notification must include 

the date of commencement of the well 

completion operation, the latitude and 

longitude coordinates of the well in 

decimal degrees to an accuracy and 

precision of five (5) decimals of a degree 

using the North American Datum of 

1983. 

(b) Reporting requirements. You must 

submit annual reports containing the 

information specified in paragraphs 

(b)(1) through (b)(6) of this section to the 

Administrator. The initial annual report 

is due 1 year after the initial startup date 

for your affected facility or 1 year after 

the date of publication of the final rule 

in the Federal Register, whichever is 

later. Subsequent annual reports are due 

on the same date each year as the initial 

annual report. If you own or operate 

more than one affected facility, you may 

submit one report for multiple affected 

facilities provided the report contains 

all of the information required as 

specified in paragraphs (b)(1) through 

(b)(6) of this section. 

(1) The general information specified 

in paragraphs (b)(1)(i) through (b)(1)(iii) 

of this section. 

(i) The company name and address of 

the affected facility. 

(ii) An identification of each affected 

facility being included in the annual 

report. 

(iii) Beginning and ending dates of the 

reporting period. 

(2) For each gas wellhead affected 

facility, the information in paragraphs 

(b)(2)(i) through (b)(2)(iii) of this 

section. 

(i) An identification of each well 

completion operation, as defined in 

§ 60.5430, for each gas wellhead affected 

facility conducted during the reporting 

period; 

(ii) A record of deviations in cases 

where well completion operations with 

hydraulic fracturing were not performed 

in compliance with the requirements 


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specified in § 60.5375 for each gas well 

affected facility. 

(iii) Records specified in § 60.5375(b) 

for each well completion operation that 

occurred during the reporting period. 

(3) For each centrifugal compressor 

affected facility installed during the 

reporting period, documentation that 

the centrifugal compressor is equipped 

with dry seals. 

(4) For each reciprocating compressor 

affected facility, the information 

specified in paragraphs (b)(4)(i) and 

(b)(4)(ii) of this section. 

(i) The cumulative number of hours or 

operation since initial startup, the date 

of publication of the final rule in the 

Federal Register, or since the previous 

reciprocating compressor rod packing 

replacement, whichever is later. 

(ii) Documentation that the 

reciprocating compressor rod packing 

was replaced before the cumulative 

number of hours of operation reached 

24,000 hours. 

(5) For each pneumatic controller 

affected facility, the information 

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

(b)(5)(iv) of this section. 

(i) The date, location and 

manufacturer specifications for each 

pneumatic controller installed. 

(ii) If applicable, documentation that 

the use of high bleed pneumatic devices 

is predicated and the reasons why. 

(iii) For pneumatic controllers not 

installed at a natural gas processing 

plant, the manufacturer’s guarantee that 

the device is designed such that natural 

gas emissions are less than 6 standard 

cubic feet per hour. 

(iv) For pneumatic controllers 

installed at a natural gas processing 

plant, documentation that each 

controllers has zero natural gas 

emissions. 

(6) For each storage vessel affected 

facility, the information in paragraphs 

(b)(6)(i) and (b)(6)(ii) of this section. 

(i) If required to reduce emissions by 

complying with § 60.5395(a)(1), the 

records specified in § 63.774(b)(2) 

through (b)(8) of this chapter. 

(ii) Documentation that the annual 

average condensate throughput is less 

than 1 barrel per day per storage vessel 

and crude oil throughput is less than 21 

barrels per day per storage for meeting 

the requirements in § 60.5395(a)(1) or 

(a)(2). 

(c) Recordkeeping requirements. You 

must maintain the records identified as 

specified in § 60.7(f) and in paragraphs 

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

(1) The records for each gas wellhead 

affected facility as specified in 

paragraphs (c)(1)(i) through (c)(1)(iii). 

(i) Records identifying each well 

completion operation for each gas 

wellhead affected facility conducted 

during the reporting period; 

(ii) Record of deviations in cases 

where well completion operations with 

hydraulic fracturing were not performed 

in compliance with the requirements 

specified in § 60.5375. 

(iii) Records required in § 60.5375(b) 

or (f) for each well completion operation 

conducted for each gas wellhead 

affected facility that occurred during the 

reporting period. You must maintain the 

records specified in paragraphs 

(c)(1)(iii)(A) and (c)(1)(iii)(B) of this 

section. 

(A) For each gas wellheads affected 

facility required to comply with the 

requirements of § 60.5375(a), you must 

record: The location of the well; the 

duration of flowback; duration of 

recovery to the sales line; duration of 

combustion; duration of venting; and 

specific reasons for venting in lieu of 

capture or combustion. The duration 

must be specified in hours of time. 

(B) For each gas wellhead affected 

facility required to comply with the 

requirements of § 60.5375(f), you must 

maintain the records specified in 

paragraph (c)(1)(iii)(A) of this section 

except that you do not have to record 

the duration of recovery to the sales 

line. In addition, you must record the 

distance, in miles, of the nearest 

gathering line. 

(2) For each centrifugal compressor 

affected facility, you must maintain 

records on the type of seal system 

installed. 

(3) For each reciprocating 

compressors affected facility, you must 

maintain the records in paragraphs 

(c)(3)(i) and (c)(3)(ii) of this section. 

(i) Records of the cumulative number 

of hours of operation since initial 

startup or the date of publication of the 

final rule in the Federal Register, or the 

previous replacement of the 

reciprocating compressor rod packing, 

whichever is later. 

(ii) Records of the date and time of 

each reciprocating compressor rod 

packing replacement. 

(4) For each pneumatic controller 

affected facility, you must maintain the 

records identified in paragraphs (c)(4)(i) 

through (c)(4)(iv) of this section. 

(i) Records of the date, location and 

manufacturer specifications for each 

pneumatic controller installed. 

(ii) Records of the determination that 

the use of high bleed pneumatic devices 

is predicated and the reasons why. 

(iii) If the pneumatic controller 

affected facility is not located at a 

natural gas processing plant, records of 

the manufacturer’s guarantee that the 

device is designed such that natural gas 

emissions are less than 6 standard cubic 

feet per hour. 

(iv) If the pneumatic controller 

affected facility is located at a natural 

gas processing plant, records of the 

documentation that only instrument air 

controllers are used. 

(5) For each storage vessel affected 

facility, you must maintain the records 

identified in paragraphs (c)(5)(i) and 

(c)(5)(ii) of this section. 

(i) If required to reduce emissions by 

complying with § 63.766, the records 

specified in § 63.774(b)(2) through (8) of 

this chapter. 

(ii) Records of the determination that 

the annual average condensate 

throughput is less than 1 barrel per day 

per storage vessel and crude oil 

throughput is less than 21 barrels per 

day per storage vessel for the exemption 

under § 60.5395(a)(1) and (a)(2). 

§ 60.5421 What are my additional 

recordkeeping requirements for my affected 

facility subject to VOC requirements for 

onshore natural gas processing plants? 

(a) You must comply with the 

requirements of paragraph (b) of this 

section in addition to the requirements 

of § 60.486a. 

(b) The following recordkeeping 

requirements apply to pressure relief 

devices subject to the requirements of 

§ 60.5401(b)(1) of this subpart. 

(1) When each leak is detected as 

specified in § 60.5401(b)(2), a 

weatherproof and readily visible 

identification, marked with the 

equipment identification number, must 

be attached to the leaking equipment. 

The identification on the pressure relief 

device may be removed after it has been 

repaired. 

(2) When each leak is detected as 

specified in § 60.5401(b)(2), the 

following information must be recorded 

in a log and shall be kept for 2 years in 

a readily accessible location: 

(i) The instrument and operator 

identification numbers and the 

equipment identification number. 

(ii) The date the leak was detected 

and the dates of each attempt to repair 

the leak. 

(iii) Repair methods applied in each 

attempt to repair the leak. 

(iv) ‘‘Above 500 ppm’’ if the 

maximum instrument reading measured 

by the methods specified in paragraph 

(a) of this section after each repair 

attempt is 500 ppm or greater. 

(v) ‘‘Repair delayed’’ and the reason 

for the delay if a leak is not repaired 

within 15 calendar days after discovery 

of the leak. 

(vi) The signature of the owner or 

operator (or designate) whose decision it 

was that repair could not be effected 

without a process shutdown. 


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(vii) The expected date of successful 

repair of the leak if a leak is not repaired 

within 15 days. 

(viii) Dates of process unit shutdowns 

that occur while the equipment is 

unrepaired. 

(ix) The date of successful repair of 

the leak. 

(x) A list of identification numbers for 

equipment that are designated for no 

detectable emissions under the 

provisions of § 60.482–4a(a). The 

designation of equipment subject to the 

provisions of § 60.482–4a(a) must be 

signed by the owner or operator. 

§ 60.5422 What are my additional reporting 

requirements for my affected facility subject 

to VOC requirements for onshore natural 

gas processing plants? 

(a) You must comply with the 

requirements of paragraphs (b) and (c) of 

this section in addition to the 

requirements of § 60.487a(a), (b), (c)(2)(i) 

through (iv), and (c)(2)(vii) through 

(viii). 

(b) An owner or operator must 

include the following information in the 

initial semiannual report in addition to 

the information required in 

§ 60.487a(b)(1) through (4): Number of 

pressure relief devices subject to the 

requirements of § 60.5401(b) except for 

those pressure relief devices designated 

for no detectable emissions under the 

provisions of § 60.482–4a(a) and those 

pressure relief devices complying with 

§ 60.482–4a(c). 

(c) An owner or operator must include 

the following information in all 

semiannual reports in addition to the 

information required in 

§ 60.487a(c)(2)(i) through (vi): 

(1) Number of pressure relief devices 

for which leaks were detected as 

required in § 60.5401(b)(2); and 

(2) Number of pressure relief devices 

for which leaks were not repaired as 

required in § 60.5401(b)(3). 

§ 60.5423 What additional recordkeeping 

and reporting requirements apply to my 

sweetening unit affected facilities at 

onshore natural gas processing plants? 

(a) You must retain records of the 

calculations and measurements required 

in § 60.5405(a) and (b) and § 60.5407(a) 

through (g) for at least 2 years following 

the date of the measurements. This 

requirement is included under § 60.7(d) 

of the General Provisions. 

(b) You must submit a written report 

of excess emissions to the Administrator 

semiannually. For the purpose of these 

reports, excess emissions are defined as: 

(1) Any 24-hour period (at consistent 

intervals) during which the average 

sulfur emission reduction efficiency (R) 

is less than the minimum required 

efficiency (Z). 

(2) For any affected facility electing to 

comply with the provisions of 

§ 60.5407(b)(2), any 24-hour period 

during which the average temperature of 

the gases leaving the combustion zone 

of an incinerator is less than the 

appropriate operating temperature as 

determined during the most recent 

performance test in accordance with the 

provisions of § 60.5407(b)(2). Each 24- 

hour period must consist of at least 96 

temperature measurements equally 

spaced over the 24 hours. 

(c) To certify that a facility is exempt 

from the control requirements of these 

standards, for each facility with a design 

capacity less that 2 LT/D of H2S in the 

acid gas (expressed as sulfur) you must 

keep, for the life of the facility, an 

analysis demonstrating that the facility’s 

design capacity is less than 2 LT/D of 

H2S expressed as sulfur. 

(d) If you elect to comply with 

§ 60.5407(e) you must keep, for the life 

of the facility, a record demonstrating 

that the facility’s design capacity is less 

than 150 LT/D of H2S expressed as 

sulfur. 

(e) The requirements of paragraph (b) 

of this section remain in force until and 

unless the EPA, in delegating 

enforcement authority to a state under 

section 111(c) of the Act, approves 

reporting requirements or an alternative 

means of compliance surveillance 

adopted by such state. In that event, 

affected sources within the state will be 

relieved of obligation to comply with 

paragraph (b) of this section, provided 

that they comply with the requirements 

established by the state. 

§ 60.5425 What part of the General 

Provisions apply to me? 

Table 3 to this subpart shows which 

parts of the General Provisions in 

§§ 60.1 through 60.19 apply to you. 

§ 60.5430 What definitions apply to this 

subpart? 

As used in this subpart, all terms not 

defined herein shall have the meaning 

given them in the Act, in subpart A or 

subpart VVa of part 60; and the 

following terms shall have the specific 

meanings given them. 

Acid gas means a gas stream of 

hydrogen sulfide (H2S) and carbon 

dioxide (CO2) that has been separated 

from sour natural gas by a sweetening 

unit. 

Alaskan North Slope means the 

approximately 69,000 square-mile area 

extending from the Brooks Range to the 

Arctic Ocean. 

API Gravity means the weight per unit 

volume of hydrocarbon liquids as 

measured by a system recommended by 

the American Petroleum Institute (API) 

and is expressed in degrees. 

Centrifugal compressor means a piece 

of equipment that compresses a process 

gas by means of mechanical rotating 

vanes or impellers. 

City gate means the delivery point at 

which natural gas is transferred from a 

transmission pipeline to the local gas 

utility. 

Completion combustion device means 

any ignition device, installed 

horizontally or vertically, used in 

exploration and production operations 

to combust otherwise vented emissions 

from completions or workovers. 

Compressor means a piece of 

equipment that compresses process gas 

and is usually a centrifugal compressor 

or a reciprocating compressor. 

Compressor station means any 

permanent combination of compressors 

that move natural gas at increased 

pressure from fields, in transmission 

pipelines, or into storage. 

Condensate means a hydrocarbon 

liquid separated from natural gas that 

condenses due to changes in the 

temperature, pressure, or both, and 

remains liquid at standard conditions, 

as specified in § 60.2. For the purposes 

of this subpart, a hydrocarbon liquid 

with an API gravity equal to or greater 

than 40 degrees is considered 

condensate. 

Crude oil means crude petroleum oil 

or any other hydrocarbon liquid, which 

are produced at the well in liquid form 

by ordinary production methods, and 

which are not the result of condensation 

of gas before or after it leaves the 

reservoir. For the purposes of this 

subpart, a hydrocarbon liquid with an 

API gravity less than 40 degrees is 

considered crude oil. 

Dehydrator means a device in which 

an absorbent directly contacts a natural 

gas stream and absorbs water in a 

contact tower or absorption column 

(absorber). 

Delineation well means a well drilled 

in order to determine the boundary of a 

field or producing reservoir. 

Equipment means each pump, 

pressure relief device, open-ended valve 

or line, valve, compressor, and flange or 

other connector that is in VOC service 

or in wet gas service, and any device or 

system required by this subpart. 

Field gas means feedstock gas 

entering the natural gas processing 

plant. 

Field gas gathering means the system 

used to transport field gas from a field 

to the main pipeline in the area. 

Flare means a thermal oxidation 

system using an open (without 

enclosure) flame. 

Flowback means the process of 

allowing fluids to flow from the well 

following a treatment, either in 


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preparation for a subsequent phase of 

treatment or in preparation for cleanup 

and returning the well to production. 

Flow line means surface pipe through 

which oil and/or natural gas travels 

from the well. 

Gas-driven pneumatic controller 

means a pneumatic controller powered 

by pressurized natural gas. 

Gas processing plant process unit 

means equipment assembled for the 

extraction of natural gas liquids from 

field gas, the fractionation of the liquids 

into natural gas products, or other 

operations associated with the 

processing of natural gas products. A 

process unit can operate independently 

if supplied with sufficient feed or raw 

materials and sufficient storage facilities 

for the products. 

Gas well means a well, the principal 

production of which at the mouth of the 

well is gas. 

High-bleed pneumatic devices means 

automated, continuous bleed flow 

control devices powered by pressurized 

natural gas and used for maintaining a 

process condition such as liquid level, 

pressure, delta-pressure and 

temperature. Part of the gas power 

stream which is regulated by the process 

condition flows to a valve actuator 

controller where it vents continuously 

(bleeds) to the atmosphere at a rate in 

excess of six standard cubic feet per 

hour. 

Hydraulic fracturing means the 

process of directing pressurized liquids, 

containing water, proppant, and any 

added chemicals, to penetrate tight 

sand, shale, or coal formations that 

involve high rate, extended back flow to 

expel fracture fluids and sand during 

completions and well workovers. 

In light liquid service means that the 

piece of equipment contains a liquid 

that meets the conditions specified in 

§ 60.485a(e) or § 60.5401(h)(2) of this 

part. 

In wet gas service means that a 

compressor or piece of equipment 

contains or contacts the field gas before 

the extraction step at a gas processing 

plant process unit. 

Liquefied natural gas unit means a 

unit used to cool natural gas to the point 

at which it is condensed into a liquid 

which is colorless, odorless, noncorrosive and non-toxic. 

Low-bleed pneumatic controller 

means automated flow control devices 

powered by pressurized natural gas and 

used for maintaining a process 

condition such as liquid level, pressure, 

delta-pressure and temperature. Part of 

the gas power stream which is regulated 

by the process condition flows to a 

valve actuator controller where it vents 

continuously (bleeds) to the atmosphere 

at a rate equal to or less than six 

standard cubic feet per hour. 

Modification means any physical 

change in, or change in the method of 

operation of, an affected facility which 

increases the amount of VOC or natural 

gas emitted into the atmosphere by that 

facility or which results in the emission 

of VOC or natural gas into the 

atmosphere not previously emitted. For 

the purposes of this subpart, each 

recompletion of a fractured or 

refractured existing gas well is 

considered to be a modification. 

Natural gas liquids means the 

hydrocarbons, such as ethane, propane, 

butane, and pentane that are extracted 

from field gas. 

Natural gas processing plant (gas 

plant) means any processing site 

engaged in the extraction of natural gas 

liquids from field gas, fractionation of 

mixed natural gas liquids to natural gas 

products, or both. 

Nonfractionating plant means any gas 

plant that does not fractionate mixed 

natural gas liquids into natural gas 

products. 

Non gas-driven pneumatic device 

means an instrument that is actuated 

using other sources of power than 

pressurized natural gas; examples 

include solar, electric, and instrument 

air. 

Onshore means all facilities except 

those that are located in the territorial 

seas or on the outer continental shelf. 

Plunger lift system means an 

intermittent gas lift that uses gas 

pressure buildup in the casing-tubing 

annulus to push a steel plunger, and the 

column of fluid ahead of it, up the well 

tubing to the surface. 

Pneumatic controller means an 

automated instrument used for 

maintaining a process condition such as 

liquid level, pressure, delta-pressure 

and temperature. 

Pneumatic pump means a pump that 

uses pressurized natural gas to move a 

piston or diaphragm, which pumps 

liquids on the opposite side of the 

piston or diaphragm. 

Process unit means components 

assembled for the extraction of natural 

gas liquids from field gas, the 

fractionation of the liquids into natural 

gas products, or other operations 

associated with the processing of 

natural gas products. A process unit can 

operate independently if supplied with 

sufficient feed or raw materials and 

sufficient storage facilities for the 

products. 

Reciprocating compressor means a 

piece of equipment that increases the 

pressure of a process gas by positive 

displacement, employing linear 

movement of the driveshaft. 

Reciprocating compressor rod packing 

means a series of flexible rings in 

machined metal cups that fit around the 

reciprocating compressor piston rod to 

create a seal limiting the amount of 

compressed natural gas that escapes to 

the atmosphere. 

Reduced emissions completion means 

a well completion where gas flowback 

that is otherwise vented is captured, 

cleaned, and routed to the sales line. 

Reduced emissions recompletion 

means a well completion following 

refracturing of a gas well where gas 

flowback that is otherwise vented is 

captured, cleaned, and routed to the 

sales line. 

Reduced sulfur compounds means 

H2S, carbonyl sulfide (COS), and carbon 

disulfide (CS2). 

Routed to a process or route to a 

process means the emissions are 

conveyed to any enclosed portion of a 

process unit where the emissions are 

predominantly recycled and/or 

consumed in the same manner as a 

material that fulfills the same function 

in the process and/or transformed by 

chemical reaction into materials that are 

not regulated materials and/or 

incorporated into a product; and/or 

recovered. 

Salable quality gas means natural gas 

that meets the composition, moisture, or 

other limits set by the purchaser of the 

natural gas. 

Sales line means pipeline, generally 

small in diameter, used to transport oil 

or gas from the well to a processing 

facility or a mainline pipeline. 

Storage vessel means a stationary 

vessel or series of stationary vessels that 

are either manifolded together or are 

located at a single well site and that 

have potential for VOC emissions equal 

to or greater than 10 tpy. 

Sulfur production rate means the rate 

of liquid sulfur accumulation from the 

sulfur recovery unit. 

Sulfur recovery unit means a process 

device that recovers element sulfur from 

acid gas. 

Surface site means any combination 

of one or more graded pad sites, gravel 

pad sites, foundations, platforms, or the 

immediate physical location upon 

which equipment is physically affixed. 

Sweetening unit means a process 

device that removes hydrogen sulfide 

and/or carbon dioxide from the natural 

gas stream. 

Total Reduced Sulfur (TRS) means the 

sum of the sulfur compounds hydrogen 

sulfide, methyl mercaptan, dimethyl 

sulfide, and dimethyl disulfide as 

measured by Method 16 of appendix A 

to part 60 of this chapter. 

Total SO2 equivalents means the sum 

of volumetric or mass concentrations of 


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the sulfur compounds obtained by 

adding the quantity existing as SO2 to 

the quantity of SO2 that would be 

obtained if all reduced sulfur 

compounds were converted to SO2

(ppmv or kg/dscm (lb/dscf)). 

Underground storage tank means a 

storage tank stored below ground. 

Well means an oil or gas well, a hole 

drilled for the purpose of producing oil 

or gas, or a well into which fluids are 

injected. 

Well completion means the process 

that allows for the flow of petroleum or 

natural gas from newly drilled wells to 

expel drilling and reservoir fluids and 

tests the reservoir flow characteristics, 

steps which may vent produced gas to 

the atmosphere via an open pit or tank. 

Well completion also involves 

connecting the well bore to the 

reservoir, which may include treating 

the formation or installing tubing, 

packer(s), or lifting equipment. 

Well completion operation means any 

well completion or well workover 

occurring at a gas wellhead affected 

facility. 

Well site means the areas that are 

directly disturbed during the drilling 

and subsequent operation of, or affected 

by, production facilities directly 

associated with any oil well, gas well, 

or injection well and its associated well 

pad. 

Wellhead means the piping, casing, 

tubing and connected valves protruding 

above the earth’s surface for an oil and/ 

or natural gas well. The wellhead ends 

where the flow line connects to a 

wellhead valve. The wellhead does not 

include other equipment at the well site 

except for any conveyance through 

which gas is vented to the atmosphere. 

Wildcat well means a well outside 

known fields or the first well drilled in 

an oil or gas field where no other oil and 

gas production exists. 

TABLE 1 TO SUBPART OOOO OF PART 60—REQUIRED MINIMUM INITIAL SO2 EMISSION REDUCTION EFFICIENCY (Zi) 

H2S content of acid gas (Y), % 

Sulfur feed rate (X), LT/D 

2.0 ≤ X ≤ 5.0 5.0 < X ≤ 15.0 15.0 < X ≤ 300.0 X > 300.0 

Y ≥ 50 ....................................... 79.0 88.51X0.0101Y0.0125 or 99.9, whichever is smaller 

20 ≤ Y < 50 ............................... 79.0 88.5X0.0101Y0.0125 or 97.9, whichever is smaller 97.9 

10 ≤ Y < 20 ............................... 79.0 88.5X0.0101Y0.0125 ......................

or 97.9, whichever is smaller ...

93.5 93.5 

Y < 10 ....................................... 79.0 79.0 79.0 79.0 

TABLE 2 TO SUBPART OOOO OF PART 60—REQUIRED MINIMUM SO2 EMISSION REDUCTION EFFICIENCY (Zc) 

H2S content of acid gas (Y), % 

Sulfur feed rate (X), LT/D 

2.0 ≤ X ≤ 5.0 5.0 < X ≤ 15.0 15.0 < X ≤ 300.0 X > 300.0 

Y ≥ 50 ....................................... 74.0 85.35X0.0144Y0.0128 or 99.9, whichever is smaller 

20 ≤ Y < 50 ............................... 74.0 85.35X0.0144Y0.0128 or 97.9, whichever is smaller 97.5 

10 ≤ Y < 20 ............................... 74.0 85.35X0.0144Y0.0128 ....................

or 90.8, whichever is smaller ...

90.8 90.8 

Y < 10 ....................................... 74.0 74.0 74.0 74.0 

E = The sulfur emission rate expressed as 

elemental sulfur, kilograms per hour (kg/ 

hr) [pounds per hour (lb/hr)], rounded to 

one decimal place. 

R = The sulfur emission reduction efficiency 

achieved in percent, carried to one 

decimal place. 

S = The sulfur production rate, kilograms per 

hour (kg/hr) [pounds per hour (lb/hr)], 

rounded to one decimal place. 

X = The sulfur feed rate from the sweetening 

unit (i.e., the H2S in the acid gas), 

expressed as sulfur, Mg/D(LT/D), 

rounded to one decimal place. 

Y = The sulfur content of the acid gas from 

the sweetening unit, expressed as mole 

percent H2S (dry basis) rounded to one 

decimal place. 

Z = The minimum required sulfur dioxide 

(SO2) emission reduction efficiency, 

expressed as percent carried to one 

decimal place. Zi refers to the reduction 

efficiency required at the initial 

performance test. Zc refers to the 

reduction efficiency required on a 

continuous basis after compliance with 

Zi has been demonstrated. 

TABLE 3 TO SUBPART OOOO OF PART 60—APPLICABILITY OF GENERAL PROVISIONS TO SUBPART OOOO 

[As stated in § 60.5425, you must comply with the following applicable General Provisions] 

General provisions 

citation Subject of citation Applies to subpart? Explanation 

§ 60.1 ............................. General applicability of the General Provisions ... Yes. 

§ 60.2 ............................. Definitions ............................................................. Yes. ............... Additional terms defined in § 60.5430. 

§ 60.3 ............................. Units and abbreviations ........................................ Yes. 

§ 60.4 ............................. Address ................................................................ Yes. 

§ 60.5 ............................. Determination of construction or modification ...... Yes. 

§ 60.6 ............................. Review of plans .................................................... Yes. 

§ 60.7 ............................. Notification and record keeping ........................... Yes ................ Except that § 60.7 only applies as specified in 

§ 60.5420(a). 


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TABLE 3 TO SUBPART OOOO OF PART 60—APPLICABILITY OF GENERAL PROVISIONS TO SUBPART OOOO—Continued 

[As stated in § 60.5425, you must comply with the following applicable General Provisions] 

General provisions 

citation Subject of citation Applies to subpart? Explanation 

§ 60.8 ............................. Performance tests ................................................ No .................. Performance testing is required for storage vessels as specified in 40 CFR part 63, subpart 

HH. 

§ 60.9 ............................. Availability of information ..................................... Yes. 

§ 60.10 ........................... State authority ...................................................... Yes. 

§ 60.11 ........................... Compliance with standards and maintenance requirements.No .................. Requirements are specified in subpart OOOO. 

§ 60.12 ........................... Circumvention ....................................................... Yes. 

§ 60.13 ........................... Monitoring requirements ....................................... Yes ................ Continuous monitors are required for storage 

vessels. 

§ 60.14 ........................... Modification .......................................................... Yes. 

§ 60.15 ........................... Reconstruction ...................................................... Yes. 

§ 60.16 ........................... Priority list ............................................................. Yes. 

§ 60.17 ........................... Incorporations by reference ................................. Yes. 

§ 60.18 ........................... General control device requirements ................... Yes. 

§ 60.19 ........................... General notification and reporting requirement ... Yes. 

PART 63—[AMENDED] 

8. The authority citation for part 63 

continues to read as follows: 

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

9. Section 63.14 is amended by: 

a. Adding paragraphs (b)(69), (b)(70), 

(b)(71) and (b)(72); and 

b. Revising paragraph (i)(1) to read as 

follows: 

§ 63.14 Incorporations by reference. 

* * * * * 

(b) * * * 

* * * * * 

(69) ASTM D1945–03(2010) Standard 

Test Method for Analysis of Natural Gas 

by Gas Chromatography, IBR approved 

for §§ 63.772 and 63.1282. 

(70) ASTM D5504–08 Standard Test 

Method for Determination of Sulfur 

Compounds in Natural Gas and Gaseous 

Fuels by Gas Chromatography and 

Chemiluminescence, IBR approved for 

§§ 63.772 and 63.1282. 

(71) ASTM D3588–98(2003) Standard 

Practice for Calculating Heat Value, 

Compressibility Factor, and Relative 

Density of Gaseous Fuels, IBR approved 

for §§ 63.772 and 63.1282. 

(72) ASTM D4891–89(2006) Standard 

Test Method for Heating Value of Gases 

in Natural Gas Range by Stoichiometric 

Combustion, IBR approved for §§ 63.772 

and 63.1282. 

* * * * * 

(i) * * * 

(1) ANSI/ASME PTC 19.10–1981, 

Flue and Exhaust Gas Analyses [Part 10, 

Instruments and Apparatus], issued 

August 31, 1981 IBR approved for 

§§ 63.309(k)(1)(iii), 63.771(e), 63.865(b), 

63.1281(d), 63.3166(a)(3), 

63.3360(e)(1)(iii), 63.3545(a)(3), 

63.3555(a)(3), 63.4166(a)(3), 

63.4362(a)(3), 63.4766(a)(3), 

63.4965(a)(3), 63.5160(d)(1)(iii), 

63.9307(c)(2), 63.9323(a)(3), 

63.11148(e)(3)(iii), 63.11155(e)(3), 

63.11162(f)(3)(iii) and (f)(4), 

63.11163(g)(1)(iii) and (g)(2), 

63.11410(j)(1)(iii), 63.11551(a)(2)(i)(C), 

63.11646(a)(1)(iii), table 5 to subpart 

DDDDD of this part, and table 1 to 

subpart ZZZZZ of this part. 

* * * * * 

Subpart HH—[Amended] 

10. Section 63.760 is amended by: 

a. Revising paragraph (a)(1) 

introductory text; 

b. Revising paragraph (a)(1)(iii); 

c. Revising paragraph (a)(2); 

d. Revising paragraph (b)(1)(ii); 

e. Revising paragraph (f) introductory 

text; 

f. Revising paragraph (f)(1); 

g. Revising paragraph (f)(2); and 

h. Adding paragraphs (f)(7), (f)(8), 

(f)(9) and (f)(10) to read as follows: 

§ 63.760 Applicability and designation of 

affected source. 

(a) * * * 

(1) Facilities that are major or area 

sources of hazardous air pollutants 

(HAP) as defined in § 63.761. Emissions 

for major source determination purposes 

can be estimated using the maximum 

natural gas or hydrocarbon liquid 

throughput, as appropriate, calculated 

in paragraphs (a)(1)(i) through (iii) of 

this section. As an alternative to 

calculating the maximum natural gas or 

hydrocarbon liquid throughput, the 

owner or operator of a new or existing 

source may use the facility’s design 

maximum natural gas or hydrocarbon 

liquid throughput to estimate the 

maximum potential emissions. Other 

means to determine the facility’s major 

source status are allowed, provided the 

information is documented and 

recorded to the Administrator’s 

satisfaction in accordance with 

§ 63.10(b)(3). A facility that is 

determined to be an area source, but 

subsequently increases its emissions or 

its potential to emit above the major 

source levels, and becomes a major 

source, must comply thereafter with all 

provisions of this subpart applicable to 

a major source starting on the applicable 

compliance date specified in paragraph 

(f) of this section. Nothing in this 

paragraph is intended to preclude a 

source from limiting its potential to emit 

through other appropriate mechanisms 

that may be available through the 

permitting authority. 

* * * * * 

(iii) The owner or operator shall 

determine the maximum values for 

other parameters used to calculate 

emissions as the maximum for the 

period over which the maximum natural 

gas or hydrocarbon liquid throughput is 

determined in accordance with 

paragraph (a)(1)(i)(A) or (B) of this 

section. Parameters, other than glycol 

circulation rate, shall be based on either 

highest measured values or annual 

average. For estimating maximum 

potential emissions from glycol 

dehydration units, the glycol circulation 

rate used in the calculation shall be the 

unit’s maximum rate under its physical 

and operational design consistent with 

the definition of potential to emit in 

§ 63.2. 

(2) Facilities that process, upgrade, or 

store hydrocarbon liquids prior to the 

point where hydrocarbon liquids enter 

either the Organic Liquids Distribution 

(Non-gasoline) or Petroleum Refineries 

source categories. 

* * * * * 


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(b) * * * 

(1) * * * 

(ii) Each storage vessel; 

* * * * * 

(f) The owner or operator of an 

affected major source shall achieve 

compliance with the provisions of this 

subpart by the dates specified in 

paragraphs (f)(1), (f)(2), and (f)(7) 

through (f)(10) of this section. The 

owner or operator of an affected area 

source shall achieve compliance with 

the provisions of this subpart by the 

dates specified in paragraphs (f)(3) 

through (f)(6) of this section. 

(1) Except as specified in paragraphs 

(f)(7) through (10) of this section, the 

owner or operator of an affected major 

source, the construction or 

reconstruction of which commenced 

before February 6, 1998, shall achieve 

compliance with the applicable 

provisions of this subpart no later than 

June 17, 2002, except as provided for in 

§ 63.6(i). The owner or operator of an 

area source, the construction or 

reconstruction of which commenced 

before February 6, 1998, that increases 

its emissions of (or its potential to emit) 

HAP such that the source becomes a 

major source that is subject to this 

subpart shall comply with this subpart 

3 years after becoming a major source. 

(2) Except as specified in paragraphs 

(f)(7) through (10) of this section, the 

owner or operator of an affected major 

source, the construction or 

reconstruction of which commences on 

or after February 6, 1998, shall achieve 

compliance with the applicable 

provisions of this subpart immediately 

upon initial startup or June 17, 1999, 

whichever date is later. Area sources, 

other than production field facilities 

identified in (f)(9) of this section, the 

construction or reconstruction of which 

commences on or after February 6, 1998, 

that become major sources shall comply 

with the provisions of this standard 

immediately upon becoming a major 

source. 

* * * * * 

(7) Each affected small glycol 

dehydration unit and each storage 

vessel that is not a storage vessel with 

the potential for flash emissions located 

at a major source, that commenced 

construction before August 23, 2011 

must achieve compliance no later than 

3 years after the date of publication of 

the final rule in the Federal Register, 

except as provided in § 63.6(i). 

(8) Each affected small glycol 

dehydration unit and each storage 

vessel that is not a storage vessel with 

the potential for flash emissions, both as 

defined in § 63.761, located at a major 

source, that commenced construction on 

or after August 23, 2011 must achieve 

compliance immediately upon initial 

startup or the date of publication of the 

final rule in the Federal Register, 

whichever is later. 

(9) A production field facility, as 

defined in § 63.761, constructed before 

August 23, 2011 that was previously 

determined to be an area source but 

becomes a major source (as defined in 

paragraph 3 of the major source 

definition in § 63.761) on the date of 

publication of the final rule in the 

Federal Register must achieve 

compliance no later than 3 years after 

the date of publication of the final rule 

in the Federal Register, except as 

provided in § 63.6(i). 

(10) Each large glycol dehydration 

unit, as defined in § 63.761, that has 

complied with the provisions of this 

subpart prior to August 23, 2011 by 

reducing its benzene emissions to less 

than 0.9 megagrams per year must 

achieve compliance no later than 90 

days after the date of publication of the 

final rule in the Federal Register, except 

as provided in § 63.6(i). 

* * * * * 

11. Section 63.761 is amended by: 

a. Adding, in alphabetical order, new 

definitions for the terms ‘‘affirmative 

defense,’’ ‘‘BTEX,’’ ‘‘flare,’’ ‘‘large glycol 

dehydration units’’ and ‘‘small glycol 

dehydration units’’; 

b. Revising the definitions for 

‘‘associated equipment,’’ ‘‘facility,’’ 

‘‘glycol dehydration unit baseline 

operations,’’ and ‘‘temperature 

monitoring device’’; and 

c. Revising paragraph (3) of the 

definition for ‘‘major source’’ to read as 

follows: 

§ 63.761 Definitions. 

* * * * * 

Affirmative defense means, in the 

context of an enforcement proceeding, a 

response or defense put forward by a 

defendant, regarding which the 

defendant has the burden of proof, and 

the merits of which are independently 

and objectively evaluated in a judicial 

or administrative proceeding. 

* * * * * 

Associated equipment, as used in this 

subpart and as referred to in section 

112(n)(4) of the Act, means equipment 

associated with an oil or natural gas 

exploration or production well, and 

includes all equipment from the 

wellbore to the point of custody 

transfer, except glycol dehydration units 

and storage vessels. 

* * * * * 

BTEX means benzene, toluene, ethyl 

benzene and xylene. 

* * * * * 

Facility means any grouping of 

equipment where hydrocarbon liquids 

are processed, upgraded (i.e., remove 

impurities or other constituents to meet 

contract specifications), or stored; or 

where natural gas is processed, 

upgraded, or stored. For the purpose of 

a major source determination, facility 

(including a building, structure, or 

installation) means oil and natural gas 

production and processing equipment 

that is located within the boundaries of 

an individual surface site as defined in 

this section. Equipment that is part of a 

facility will typically be located within 

close proximity to other equipment 

located at the same facility. Pieces of 

production equipment or groupings of 

equipment located on different oil and 

gas leases, mineral fee tracts, lease 

tracts, subsurface or surface unit areas, 

surface fee tracts, surface lease tracts, or 

separate surface sites, whether or not 

connected by a road, waterway, power 

line or pipeline, shall not be considered 

part of the same facility. Examples of 

facilities in the oil and natural gas 

production source category include, but 

are not limited to, well sites, satellite 

tank batteries, central tank batteries, a 

compressor station that transports 

natural gas to a natural gas processing 

plant, and natural gas processing plants. 

* * * * * 

Flare means a thermal oxidation 

system using an open flame (i.e., 

without enclosure). 

* * * * * 

Glycol dehydration unit baseline 

operations means operations 

representative of the large glycol 

dehydration unit operations as of June 

17, 1999 and the small glycol 

dehydrator unit operations as of August 

23, 2011. For the purposes of this 

subpart, for determining the percentage 

of overall HAP emission reduction 

attributable to process modifications, 

baseline operations shall be parameter 

values (including, but not limited to, 

glycol circulation rate or glycol-HAP 

absorbency) that represent actual longterm conditions (i.e., at least 1 year). 

Glycol dehydration units in operation 

for less than 1 year shall document that 

the parameter values represent expected 

long-term operating conditions had 

process modifications not been made. 

* * * * * 

Large glycol dehydration unit means a 

glycol dehydration unit with an actual 

annual average natural gas flowrate 

equal to or greater than 85 thousand 

standard cubic meters per day and 

actual annual average benzene 

emissions equal to or greater than 0.90 


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Mg/yr, determined according to 

§ 63.772(b). 

* * * * * 

Major source * * * 

(3) For facilities that are production 

field facilities, only HAP emissions from 

glycol dehydration units and storage 

vessels 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. 

* * * * * 

Small glycol dehydration unit means 

a glycol dehydration unit, located at a 

major source, with an actual annual 

average natural gas flowrate less than 85 

thousand standard cubic meters per day 

or actual annual average benzene 

emissions less than 0.90 Mg/yr, 

determined according to § 63.772(b). 

* * * * * 

Temperature monitoring device 

means an instrument used to monitor 

temperature and having a minimum 

accuracy of ± 1 percent of the 

temperature being monitored expressed 

in °C, or ± 2.5 °C, whichever is greater. 

The temperature monitoring device may 

measure temperature in degrees 

Fahrenheit or degrees Celsius, or both. 

* * * * * 

12. Section 63.762 is revised to read 

as follows: 

§ 63.762 Startups and shutdowns. 

(a) The provisions set forth in this 

subpart shall apply at all times. 

(b) The owner or operator shall not 

shut down items of equipment that are 

required or utilized for compliance with 

the provisions of this subpart during 

times when emissions are being routed 

to such items of equipment, if the 

shutdown would contravene 

requirements of this subpart applicable 

to such items of equipment. This 

paragraph does not apply if the owner 

or operator must shut down the 

equipment to avoid damage due to a 

contemporaneous startup or shutdown, 

of the affected source or a portion 

thereof. 

(c) During startups and shutdowns, 

the owner or operator shall implement 

measures to prevent or minimize excess 

emissions to the maximum extent 

practical. 

(d) In response to an action to enforce 

the standards set forth in this subpart, 

you may assert an affirmative defense to 

a claim for civil penalties for 

exceedances of such standards that are 

caused by malfunction, as defined in 40 

CFR 63.2. Appropriate penalties may be 

assessed, however, if you fail to meet 

your burden of proving all the 

requirements in the affirmative defense. 

The affirmative defense shall not be 

available for claims for injunctive relief. 

(1) To establish the affirmative 

defense in any action to enforce such a 

limit, you must timely meet the 

notification requirements in paragraph 

(d)(2) of this section, and must prove by 

a preponderance of evidence that: 

(i) The excess emissions: 

(A) Were caused by a sudden, 

infrequent, and unavoidable failure of 

air pollution control and monitoring 

equipment, process equipment, or a 

process to operate in a normal or usual 

manner; and 

(B) Could not have been prevented 

through careful planning, proper design 

or better operation and maintenance 

practices; and 

(C) Did not stem from any activity or 

event that could have been foreseen and 

avoided, or planned for; and 

(D) Were not part of a recurring 

pattern indicative of inadequate design, 

operation, or maintenance; and 

(ii) Repairs were made as 

expeditiously as possible when the 

applicable emission limitations were 

being exceeded. Off-shift and overtime 

labor were used, to the extent 

practicable to make these repairs; and 

(iii) The frequency, amount and 

duration of the excess emissions 

(including any bypass) were minimized 

to the maximum extent practicable 

during periods of such emissions; and 

(iv) If the excess emissions 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 

(v) All possible steps were taken to 

minimize the impact of the excess 

emissions on ambient air quality, the 

environment, and human health; and 

(vi) All emissions monitoring and 

control systems were kept in operation 

if at all possible, consistent with safety 

and good air pollution control practices; 

and 

(vii) All of the actions in response to 

the excess emissions were documented 

by properly signed, contemporaneous 

operating logs; and 

(viii) At all times, the affected source 

was operated in a manner consistent 

with good practices for minimizing 

emissions; and 

(ix) A written root cause analysis has 

been prepared to determine, correct, and 

eliminate the primary causes of the 

malfunction and the excess emissions 

resulting from the malfunction event at 

issue. The analysis shall also specify, 

using best monitoring methods and 

engineering judgment, the amount of 

excess emissions that were the result of 

the malfunction. 

(2) Notification. The owner or 

operator of the affected source 

experiencing exceedance of its emission 

limit(s) during a malfunction shall 

notify the Administrator by telephone or 

facsimile transmission as soon as 

possible, but no later than two business 

days after the initial occurrence of the 

malfunction, if it wishes to avail itself 

of an affirmative defense to civil 

penalties for that malfunction. The 

owner or operator seeking to assert an 

affirmative defense shall also submit a 

written report to the Administrator 

within 45 days of the initial occurrence 

of the exceedance of the standard in this 

subpart to demonstrate, with all 

necessary supporting documentation, 

that it has met the requirements set forth 

in paragraph (d)(1) of this section. The 

owner or operator may seek an 

extension of this deadline for up to 30 

additional days by submitting a written 

request to the Administrator before the 

expiration of the 45 day period. Until a 

request for an extension has been 

approved by the Administrator, the 

owner or operator is subject to the 

requirement to submit such report 

within 45 days of the initial occurrence 

of the exceedance. 

13. Section 63.764 is amended by: 

a. Revising paragraph (c)(2) 

introductory text; 

b. Revising paragraph (e)(1) 

introductory text; 

c. Revising paragraph (i); and 

d. Adding paragraph (j) to read as 

follows: 

§ 63.764 General standards. 

* * * * * 

(c) * * * 

(2) For each storage vessel subject to 

this subpart, the owner or operator shall 

comply with the requirements specified 

in paragraphs (c)(2)(i) through (iii) of 

this section. 

* * * * * 

(e) Exemptions. (1) The owner or 

operator of an area source is exempt 

from the requirements of paragraph (d) 

of this section if the criteria listed in 

paragraph (e)(1)(i) or (ii) of this section 

are met, except that the records of the 

determination of these criteria must be 

maintained as required in § 63.774(d)(1). 

* * * * * 

(i) In all cases where the provisions of 

this subpart require an owner or 

operator to repair leaks by a specified 

time after the leak is detected, it is a 

violation of this standard to fail to take 

action to repair the leak(s) within the 

specified time. If action is taken to 

repair the leak(s) within the specified 


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time, failure of that action to 

successfully repair the leak(s) is not a 

violation of this standard. However, if 

the repairs are unsuccessful, and a leak 

is detected, the owner or operator shall 

take further action as required by the 

applicable provisions of this subpart. 

(j) At all times the owner or operator 

must operate and maintain any affected 

source, including associated air 

pollution control equipment and 

monitoring equipment, in a manner 

consistent with safety and good air 

pollution control practices for 

minimizing emissions. Determination of 

whether such operation and 

maintenance procedures are being used 

will be based on information available 

to the Administrator which may 

include, but is not limited to, 

monitoring results, review of operation 

and maintenance procedures, review of 

operation and maintenance records, and 

inspection of the source. 

14. Section 63.765 is amended by: 

a. Revising paragraph (a); 

b. Revising paragraph (b)(1); 

c. Revising paragraph (c)(2); and 

d. Revising paragraph (c)(3) to read as 

follows: 

§ 63.765 Glycol dehydration unit process 

vent standards. 

(a) This section applies to each glycol 

dehydration unit subject to this subpart 

that must be controlled for air emissions 

as specified in either paragraph (c)(1)(i) 

or paragraph (d)(1)(i) of § 63.764. 

(b) * * * 

(1) For each glycol dehydration unit 

process vent, the owner or operator 

shall control air emissions by either 

paragraph (b)(1)(i), (ii), or (iii) of this 

section. 

(i) The owner or operator of a large 

glycol dehydration unit, as defined in 

§ 63.761, shall connect the process vent 

to a control device or a combination of 

control devices through a closed-vent 

system. The closed-vent system shall be 

designed and operated in accordance 

with the requirements of § 63.771(c). 

The control device(s) shall be designed 

and operated in accordance with the 

requirements of § 63.771(d). 

(ii) The owner or operator of a glycol 

dehydration unit located at an area 

source, that must be controlled as 

specified in § 63.764(d)(1)(i), shall 

connect the process vent to a control 

device or combination of control 

devices through a closed-vent system 

and the outlet benzene emissions from 

the control device(s) shall be reduced to 

a level less than 0.90 megagrams per 

year. The closed-vent system shall be 

designed and operated in accordance 

with the requirements of § 63.771(c). 

The control device(s) shall be designed 

and operated in accordance with the 

requirements of § 63.771(d), except that 

the performance levels specified in 

§ 63.771(d)(1)(i) and (ii) do not apply. 

(iii) You must limit BTEX emissions 

from each small glycol dehydration unit 

process vent, as defined in § 63.761, to 

the limit determined in Equation 1 of 

this section. The limit must be met in 

accordance with one of the alternatives 

specified in paragraphs (b)(1)(iii)(A) 

through (D) of this section. 

Where: 

ELBTEX = Unit-specific BTEX emission limit, 

megagrams per year; 

1.10 × 10¥4 = BTEX emission limit, grams 

BTEX/standard cubic meter = ppmv; 

Throughput = Annual average daily natural 

gas throughput, standard cubic meters 

per day; 

Ci,BTEX = BTEX concentration of the natural 

gas at the inlet to the glycol dehydration 

unit, ppmv. 

(A) Connect the process vent to a 

control device or combination of control 

devices through a closed-vent system. 

The closed vent system shall be 

designed and operated in accordance 

with the requirements of § 63.771(c). 

The control device(s) shall be designed 

and operated in accordance with the 

requirements of § 63.771(f). 

(B) Meet the emissions limit through 

process modifications in accordance 

with the requirements specified in 

§ 63.771(e). 

(C) Meet the emissions limit for each 

small glycol dehydration unit using a 

combination of process modifications 

and one or more control devices through 

the requirements specified in 

paragraphs (b)(1)(iii)(A) and (B) of this 

section. 

(D) Demonstrate that the emissions 

limit is met through actual uncontrolled 

operation of the small glycol 

dehydration unit. Document operational 

parameters in accordance with the 

requirements specified in § 63.771(e) 

and emissions in accordance with the 

requirements specified in § 63.772(b)(2). 

* * * * * 

(c) * * * 

(2) The owner or operator shall 

demonstrate, to the Administrator’s 

satisfaction, that the total HAP 

emissions to the atmosphere from the 

large glycol dehydration unit process 

vent are reduced by 95.0 percent 

through process modifications, or a 

combination of process modifications 

and one or more control devices, in 

accordance with the requirements 

specified in § 63.771(e). 

(3) Control of HAP emissions from a 

GCG separator (flash tank) vent is not 

required if the owner or operator 

demonstrates, to the Administrator’s 

satisfaction, that total emissions to the 

atmosphere from the glycol dehydration 

unit process vent are reduced by one of 

the levels specified in paragraph 

(c)(3)(i), (ii), or (iii) of this section, 

through the installation and operation of 

controls as specified in paragraph (b)(1) 

of this section. 

(i) For any large glycol dehydration 

unit, HAP emissions are reduced by 

95.0 percent or more. 

(ii) For area source dehydration units, 

benzene emissions are reduced to a 

level less than 0.90 megagrams per year. 

(iii) For each small glycol dehydration 

unit, BTEX emissions are reduced to a 

level less than the limit calculated by 

paragraph (b)(1)(iii) of this section. 

15. Section 63.766 is amended by: 

a. Revising paragraph (a); 

b. Revising paragraph (b) introductory 

text; 

c. Revising paragraph (b)(1); and 

d. Revising paragraph (d) to read as 

follows: 

§ 63.766 Storage vessel standards. 

(a) This section applies to each 

storage vessel (as defined in § 63.761) 

subject to this subpart. 

(b) The owner or operator of a storage 

vessel (as defined in § 63.761) shall 

comply with one of the control 

requirements specified in paragraphs 

(b)(1) and (2) of this section. 

(1) The owner or operator shall equip 

the affected storage vessel with a cover 

that is connected, through a closed-vent 

system that meets the conditions 

specified in § 63.771(c), to a control 

device or a combination of control 

devices that meets any of the conditions 

specified in § 63.771(d). The cover shall 

be designed and operated in accordance 

with the requirements of § 63.771(b). 

* * * * * 

(d) This section does not apply to 

storage vessels for which the owner or 

operator is subject to and controlled 

under the requirements specified in 40 


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CFR part 60, subpart Kb; or the 

requirements specified under 40 CFR 

part 63 subparts G or CC. 

16. Section 63.769 is amended by: 

a. Revising paragraph (b); 

b. Revising paragraph (c) introductory 

text; and 

b. Revising paragraph (c)(8) to read as 

follows: 

§ 63.769 Equipment leak standards. 

* * * * * 

(b) This section does not apply to 

ancillary equipment and compressors 

for which the owner or operator is 

subject to and controlled under the 

requirements specified in subpart H of 

this part; or the requirements specified 

in 40 CFR part 60, subpart KKK. 

(c) For each piece of ancillary 

equipment and each compressor subject 

to this section located at an existing or 

new source, the owner or operator shall 

meet the requirements specified in 40 

CFR part 61, subpart V, §§ 61.241 

through 61.247, except as specified in 

paragraphs (c)(1) through (8) of this 

section, except for valves subject to 

§ 61.247–2(b) a leak is detected if an 

instrument reading of 500 ppm or 

greater is measured. 

* * * * * 

(8) Flares, as defined in § 63.761, used 

to comply with this subpart shall 

comply with the requirements of 

§ 63.11(b). 

17. Section 63.771 is amended by: 

a. Revising paragraph (c)(1) 

introductory text; 

b. Revising the heading of paragraph 

(d); 

c. Adding paragraph (d) introductory 

text; 

d. Revising paragraph (d)(1)(i) 

introductory text; 

e. Revising paragraph (d)(1)(i)(C); 

f. Revising paragraph (d)(1)(ii); 

g. Revising paragraph (d)(1)(iii); 

h. Revising paragraph (d)(4)(i); 

i. Revising paragraph (d)(5)(i); 

j. Revising paragraph (e)(2); 

k. Revising paragraph (e)(3) 

introductory text; 

l. Revising paragraph (e)(3)(ii); and 

m. Adding paragraph (f) to read as 

follows: 

§ 63.771 Control equipment requirements. 

* * * * * 

(c) Closed-vent system requirements. 

(1) The closed-vent system shall route 

all gases, vapors, and fumes emitted 

from the material in an emissions unit 

to a control device that meets the 

requirements specified in paragraph (d) 

of this section. 

* * * * * 

(d) Control device requirements for 

sources except small glycol dehydration 

units. Owners and operators of small 

glycol dehydration units, shall comply 

with the control device requirements in 

paragraph (f) of this section. 

(1) * * * 

(i) An enclosed combustion device 

(e.g., thermal vapor incinerator, catalytic 

vapor incinerator, boiler, or process 

heater) that is designed and operated in 

accordance with one of the following 

performance requirements: 

* * * * * 

(C) For a control device that can 

demonstrate a uniform combustion zone 

temperature during the performance test 

conducted under § 63.772(e), operates at 

a minimum temperature of 760 degrees 

C. 

* * * * * 

(ii) A vapor recovery device (e.g., 

carbon adsorption system or condenser) 

or other non-destructive control device 

that is designed and operated to reduce 

the mass content of either TOC or total 

HAP in the gases vented to the device 

by 95.0 percent by weight or greater as 

determined in accordance with the 

requirements of § 63.772(e). 

(iii) A flare, as defined in § 63.761, 

that is designed and operated in 

accordance with the requirements of 

§ 63.11(b). 

* * * * * 

(4) * * * 

(i) Each control device used to comply 

with this subpart shall be operating at 

all times when gases, vapors, and fumes 

are vented from the HAP emissions unit 

or units through the closed-vent system 

to the control device, as required under 

§ 63.765, § 63.766, and § 63.769. An 

owner or operator may vent more than 

one unit to a control device used to 

comply with this subpart. 

* * * * * 

(5) * * * 

(i) Following the initial startup of the 

control device, all carbon in the control 

device shall be replaced with fresh 

carbon on a regular, predetermined time 

interval that is no longer than the 

carbon service life established for the 

carbon adsorption system. Records 

identifying the schedule for replacement 

and records of each carbon replacement 

shall be maintained as required in 

§ 63.774(b)(7)(ix). The schedule for 

replacement shall be submitted with the 

Notification of Compliance Status 

Report as specified in § 63.775(d)(5)(iv). 

Each carbon replacement must be 

reported in the Periodic Reports as 

specified in § 63.772(e)(2)(xii). 

* * * * * 

(e) * * * 

(2) The owner or operator shall 

document, to the Administrator’s 

satisfaction, the conditions for which 

glycol dehydration unit baseline 

operations shall be modified to achieve 

the 95.0 percent overall HAP emission 

reduction, or BTEX limit determined in 

§ 63.765(b)(1)(iii), as applicable, either 

through process modifications or 

through a combination of process 

modifications and one or more control 

devices. If a combination of process 

modifications and one or more control 

devices are used, the owner or operator 

shall also establish the emission 

reduction to be achieved by the control 

device to achieve an overall HAP 

emission reduction of 95.0 percent for 

the glycol dehydration unit process vent 

or, if applicable, the BTEX limit 

determined in § 63.765(b)(1)(iii) for the 

small glycol dehydration unit process 

vent. Only modifications in glycol 

dehydration unit operations directly 

related to process changes, including 

but not limited to changes in glycol 

circulation rate or glycol-HAP 

absorbency, shall be allowed. Changes 

in the inlet gas characteristics or natural 

gas throughput rate shall not be 

considered in determining the overall 

emission reduction due to process 

modifications. 

(3) The owner or operator that 

achieves a 95.0 percent HAP emission 

reduction or meets the BTEX limit 

determined in § 63.765(b)(1)(iii), as 

applicable, using process modifications 

alone shall comply with paragraph 

(e)(3)(i) of this section. The owner or 

operator that achieves a 95.0 percent 

HAP emission reduction or meets the 

BTEX limit determined in 

§ 63.765(b)(1)(iii), as applicable, using a 

combination of process modifications 

and one or more control devices shall 

comply with paragraphs (e)(3)(i) and 

(e)(3)(ii) of this section. 

* * * * * 

(ii) The owner or operator shall 

comply with the control device 

requirements specified in paragraph (d) 

or (f) of this section, as applicable, 

except that the emission reduction or 

limit achieved shall be the emission 

reduction or limit specified for the 

control device(s) in paragraph (e)(2) of 

this section. 

(f) Control device requirements for 

small glycol dehydration units. (1) The 

control device used to meet BTEX the 

emission limit calculated in 

§ 63.765(b)(1)(iii) shall be one of the 

control devices specified in paragraphs 

(f)(1)(i) through (iii) of this section. 

(i) An enclosed combustion device 

(e.g., thermal vapor incinerator, catalytic 

vapor incinerator, boiler, or process 

heater) that is designed and operated to 

reduce the mass content of BTEX in the 

gases vented to the device as 


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determined in accordance with the 

requirements of § 63.772(e). If a boiler or 

process heater is used as the control 

device, then the vent stream shall be 

introduced into the flame zone of the 

boiler or process heater; or 

(ii) A vapor recovery device (e.g., 

carbon adsorption system or condenser) 

or other non-destructive control device 

that is designed and operated to reduce 

the mass content of BTEX in the gases 

vented to the device as determined in 

accordance with the requirements of 

§ 63.772(e); or 

(iii) A flare, as defined in § 63.761, 

that is designed and operated in 

accordance with the requirements of 

§ 63.11(b). 

(2) The owner or operator shall 

operate each control device in 

accordance with the requirements 

specified in paragraphs (f)(2)(i) and (ii) 

of this section. 

(i) Each control device used to comply 

with this subpart shall be operating at 

all times. An owner or operator may 

vent more than one unit to a control 

device used to comply with this 

subpart. 

(ii) For each control device monitored 

in accordance with the requirements of 

§ 63.773(d), the owner or operator shall 

demonstrate compliance according to 

the requirements of either § 63.772(f) or 

(h). 

(3) For each carbon adsorption system 

used as a control device to meet the 

requirements of paragraph (f)(1)(ii) of 

this section, the owner or operator shall 

manage the carbon as required under 

(d)(5)(i) and (ii) of this section. 

18. Section 63.772 is amended by: 

a. Revising paragraph (b) introductory 

text; 

b. Revising paragraph (b)(1)(ii); 

c. Revising paragraph (b)(2); 

d. Adding paragraph (d); 

e. Revising paragraph (e) introductory 

text; 

f. Revising paragraphs (e)(1)(i) 

through (v); 

g. Revising paragraph (e)(2); 

h. Revising paragraph (e)(3) 

introductory text; 

i. Revising paragraph (e)(3)(i)(B); 

j. Revising paragraph (e)(3)(iv)(C)(1); 

k. Adding paragraphs (e)(3)(v) and 

(vi); 

l. Revising paragraph (e)(4) 

introductory text; 

m. Revising paragraph (e)(4)(i); 

n. Revising paragraph (e)(5); 

o. Revising paragraph (f) introductory 

text; 

p. Adding paragraphs (f)(2) through 

(f)(6); 

q. Revising paragraph (g) introductory 

text; 

r. Revising paragraph (g)(1) and 

paragraph (g)(2) introductory text; 

s. Revising paragraph (g)(2)(iii); 

t. Revising paragraph (g)(3); 

u. Adding paragraph (h); and 

v. Adding paragraph (i) to read as 

follows: 

§ 63.772 Test methods, compliance 

procedures, and compliance 

demonstrations. 

* * * * * 

(b) Determination of glycol 

dehydration unit flowrate, benzene 

emissions, or BTEX emissions. The 

procedures of this paragraph shall be 

used by an owner or operator to 

determine glycol dehydration unit 

natural gas flowrate, benzene emissions, 

or BTEX emissions. 

(1) * * * 

(ii) The owner or operator shall 

document, to the Administrator’s 

satisfaction, the actual annual average 

natural gas flowrate to the glycol 

dehydration unit. 

(2) The determination of actual 

average benzene or BTEX emissions 

from a glycol dehydration unit shall be 

made using the procedures of either 

paragraph (b)(2)(i) or (b)(2)(ii) of this 

section. Emissions shall be determined 

either uncontrolled, or with federally 

enforceable controls in place. 

(i) The owner or operator shall 

determine actual average benzene or 

BTEX emissions using the model GRI– 

GLYCalcTM, Version 3.0 or higher, and 

the procedures presented in the 

associated GRI–GLYCalcTM Technical 

Reference Manual. Inputs to the model 

shall be representative of actual 

operating conditions of the glycol 

dehydration unit and may be 

determined using the procedures 

documented in the Gas Research 

Institute (GRI) report entitled 

‘‘Atmospheric Rich/Lean Method for 

Determining Glycol Dehydrator 

Emissions’’ (GRI–95/0368.1); or 

(ii) The owner or operator shall 

determine an average mass rate of 

benzene or BTEX emissions in 

kilograms per hour through direct 

measurement using the methods in 

§ 63.772(a)(1)(i) or (ii), or an alternative 

method according to § 63.7(f). Annual 

emissions in kilograms per year shall be 

determined by multiplying the mass rate 

by the number of hours the unit is 

operated per year. This result shall be 

converted to megagrams per year. 

* * * * * 

(d) Test procedures and compliance 

demonstrations for small glycol 

dehydration units. This paragraph 

applies to the test procedures for small 

dehydration units. 

(1) If the owner or operator is using 

a control device to comply with the 

emission limit in § 63.765(b)(1)(iii), the 

requirements of paragraph (e) of this 

section apply. Compliance is 

demonstrated using the methods 

specified in paragraph (f) of this section. 

(2) If no control device is used to 

comply with the emission limit in 

§ 63.765(b)(1)(iii), the owner or operator 

must determine the glycol dehydration 

unit BTEX emissions as specified in 

paragraphs (d)(2)(i) through (iii) of this 

section. Compliance is demonstrated if 

the BTEX emissions determined as 

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

(iii) are less than the emission limit 

calculated using the equation in 

§ 63.765(b)(1)(iii). 

(i) Method 1 or 1A, 40 CFR part 60, 

appendix A, as appropriate, shall be 

used for selection of the sampling sites 

at the outlet of the glycol dehydration 

unit process vent. Any references to 

particulate mentioned in Methods 1 and 

1A do not apply to this section. 

(ii) The gas volumetric flowrate shall 

be determined using Method 2, 2A, 2C, 

or 2D, 40 CFR part 60, appendix A, as 

appropriate. 

(iii) The BTEX emissions from the 

outlet of the glycol dehydration unit 

process vent shall be determined using 

the procedures specified in paragraph 

(e)(3)(v) of this section. As an 

alternative, the mass rate of BTEX at the 

outlet of the glycol dehydration unit 

process vent may be calculated using 

the model GRI–GLYCalcTM, Version 3.0 

or higher, and the procedures presented 

in the associated GRI–GLYCalcTM

Technical Reference Manual. Inputs to 

the model shall be representative of 

actual operating conditions of the glycol 

dehydration unit and shall be 

determined using the procedures 

documented in the Gas Research 

Institute (GRI) report entitled 

‘‘Atmospheric Rich/Lean Method for 

Determining Glycol Dehydrator 

Emissions’’ (GRI–95/0368.1). When the 

BTEX mass rate is calculated for glycol 

dehydration units using the model GRI– 

GLYCalcTM, all BTEX measured by 

Method 18, 40 CFR part 60, appendix A, 

shall be summed. 

(e) Control device performance test 

procedures. This paragraph applies to 

the performance testing of control 

devices. The owners or operators shall 

demonstrate that a control device 

achieves the performance requirements 

of § 63.771(d)(1), (e)(3)(ii) or (f)(1) using 

a performance test as specified in 

paragraph (e)(3) of this section. Owners 

or operators using a condenser have the 

option to use a design analysis as 

specified in paragraph (e)(4) of this 

section. The owner or operator may 

elect to use the alternative procedures in 

paragraph (e)(5) of this section for 

performance testing of a condenser used 


emcdonald on DSK2BSOYB1PROD with PROPOSALS2
52818 Federal Register / Vol. 76, No. 163 / Tuesday, August 23, 2011 / Proposed Rules 

to control emissions from a glycol 

dehydration unit process vent. As an 

alternative to conducting a performance 

test under this section for combustion 

control devices, a control device that 

can be demonstrated to meet the 

performance requirements of 

§ 63.771(d)(1), (e)(3)(ii) or (f)(1) through 

a performance test conducted by the 

manufacturer, as specified in paragraph 

(h) of this section can be used. 

(1) * * * 

(i) Except as specified in paragraph 

(e)(2) of this section, a flare, as defined 

in § 63.761, that is designed and 

operated in accordance with § 63.11(b); 

(ii) Except for control devices used for 

small glycol dehydration units, a boiler 

or process heater with a design heat 

input capacity of 44 megawatts or 

greater; 

(iii) Except for control devices used 

for small glycol dehydration units, a 

boiler or process heater into which the 

vent stream is introduced with the 

primary fuel or is used as the primary 

fuel; 

(iv) Except for control devices used 

for small glycol dehydration units, a 

boiler or process heater burning 

hazardous waste for which the owner or 

operator has either been issued a final 

permit under 40 CFR part 270 and 

complies with the requirements of 40 

CFR part 266, subpart H; or has certified 

compliance with the interim status 

requirements of 40 CFR part 266, 

subpart H; 

(v) Except for control devices used for 

small glycol dehydration units, a 

hazardous waste incinerator for which 

the owner or operator has been issued 

a final permit under 40 CFR part 270 

and complies with the requirements of 

40 CFR part 264, subpart O; or has 

certified compliance with the interim 

status requirements of 40 CFR part 265, 

subpart O. 

* * * * * 

(2) An owner or operator shall design 

and operate each flare, as defined in 

§ 63.761, in accordance with the 

requirements specified in § 63.11(b) and 

the compliance determination shall be 

conducted using Method 22 of 40 CFR 

part 60, appendix A, to determine 

visible emissions. 

(3) For a performance test conducted 

to demonstrate that a control device 

meets the requirements of 

§ 63.771(d)(1), (e)(3)(ii) or (f)(1), the 

owner or operator shall use the test 

methods and procedures specified in 

paragraphs (e)(3)(i) through (v) of this 

section. The initial and periodic 

performance tests shall be conducted 

according to the schedule specified in 

paragraph (e)(3)(vi) of this section. 

(i) * * * 

(B) To determine compliance with the 

enclosed combustion device total HAP 

concentration limit specified in 

§ 63.765(b)(1)(iii), or the BTEX emission 

limit specified in § 63.771(f)(1) the 

sampling site shall be located at the 

outlet of the combustion device. 

* * * * * 

(iv) * * * 

(C) * * * 

(1) The emission rate correction factor 

for excess air, integrated sampling and 

analysis procedures of Method 3A or 

3B, 40 CFR part 60, appendix A, shall 

be used to determine the oxygen 

concentration. The samples shall be 

taken during the same time that the 

samples are taken for determining TOC 

concentration or total HAP 

concentration. 

* * * * * 

(v) To determine compliance with the 

BTEX emission limit specified in 

§ 63.771(f)(1) the owner or operator 

shall use one of the following methods: 

Method 18, 40 CFR part 60, appendix A; 

ASTM D6420–99 (2004), as specified in 

§ 63.772(a)(1)(ii); or any other method or 

data that have been validated according 

to the applicable procedures in Method 

301, 40 CFR part 63, appendix A. The 

following procedures shall be used to 

calculate BTEX emissions: 

(A) The minimum sampling time for 

each run shall be 1 hour in which either 

an integrated sample or a minimum of 

four grab samples shall be taken. If grab 

sampling is used, then the samples shall 

be taken at approximately equal 

intervals in time, such as 15-minute 

intervals during the run. 

(B) The mass rate of BTEX (Eo) shall 

be computed using the equations and 

procedures specified in paragraphs 

(e)(3)(v)(B)(1) and (2) of this section. 

(1) The following equation shall be 

used: 

Where: 

Eo= Mass rate of BTEX at the outlet of the 

control device, dry basis, kilogram per 

hour. 

Coj= Concentration of sample component j of 

the gas stream at the outlet of the control 

device, dry basis, parts per million by 

volume. 

Moj= Molecular weight of sample component 

j of the gas stream at the outlet of the 

control device, gram/gram-mole. 

Qo= Flowrate of gas stream at the outlet of 

the control device, dry standard cubic 

meter per minute. 

K2= Constant, 2.494 × 10¥6 (parts per 

million) (gram-mole per standard cubic 

meter) (kilogram/gram) (minute/hour), 

where standard temperature (gram-mole 

per standard cubic meter) is 20 degrees 

C. 

n = Number of components in sample. 

(2) When the BTEX mass rate is 

calculated, only BTEX compounds 

measured by Method 18, 40 CFR part 

60, appendix A, or ASTM D6420–99 

(2004) as specified in § 63.772(a)(1)(ii), 

shall be summed using the equations in 

paragraph (e)(3)(v)(B)(1) of this section. 

(vi) The owner or operator shall 

conduct performance tests according to 

the schedule specified in paragraphs 

(e)(3)(vi)(A) and (B) of this section. 

(A) An initial performance test shall 

be conducted within 180 days after the 

compliance date that is specified for 

each affected source in § 63.760(f)(7) 

through (8), except that the initial 

performance test for existing 

combustion control devices at existing 

major sources shall be conducted no 

later than 3 years after the date of 

publication of the final rule in the 

Federal Register. If the owner or 

operator of an existing combustion 

control device at an existing major 

source chooses to replace such device 

with a control device whose model is 

tested under § 63.772(h), then the newly 

installed device shall comply with all 

provisions of this subpart no later than 

3 years after the date of publication of 

the final rule in the Federal Register. 

The performance test results shall be 

submitted in the Notification of 

Compliance Status Report as required in 

§ 63.775(d)(1)(ii). 

(B) Periodic performance tests shall be 

conducted for all control devices 

required to conduct initial performance 

tests except as specified in paragraphs 

(e)(3)(vi)(B)(1) and (2) of this section. 

The first periodic performance test shall 

be conducted no later than 60 months 

after the initial performance test 

required in paragraph (e)(3)(vi)(A) of 

this section. Subsequent periodic 

performance tests shall be conducted at 

intervals no longer than 60 months 

following the previous periodic 

performance test or whenever a source 

desires to establish a new operating 

limit. The periodic performance test 

results must be submitted in the next 

Periodic Report as specified in 

§ 63.775(e)(2)(xi). Combustion control 

devices meeting the criteria in either 

paragraph (e)(3)(vi)(B)(1) or (2) of this 

section are not required to conduct 

periodic performance tests. 

(1) A control device whose model is 

tested under, and meets the criteria of, 

§ 63.772(h), or 

(2) A combustion control device 

tested under § 63.772(e) that meets the 

outlet TOC or HAP performance level 

specified in § 63.771(d)(1)(i)(B) and that 


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establishes a correlation between firebox 

or combustion chamber temperature and 

the TOC or HAP performance level. 

(4) For a condenser design analysis 

conducted to meet the requirements of 

§ 63.771(d)(1), (e)(3)(ii), or (f)(1), the 

owner or operator shall meet the 

requirements specified in paragraphs 

(e)(4)(i) and (e)(4)(ii) of this section. 

Documentation of the design analysis 

shall be submitted as a part of the 

Notification of Compliance Status 

Report as required in § 63.775(d)(1)(i). 

(i) The condenser design analysis 

shall include an analysis of the vent 

stream composition, constituent 

concentrations, flowrate, relative 

humidity, and temperature, and shall 

establish the design outlet organic 

compound concentration level, design 

average temperature of the condenser 

exhaust vent stream, and the design 

average temperatures of the coolant 

fluid at the condenser inlet and outlet. 

As an alternative to the condenser 

design analysis, an owner or operator 

may elect to use the procedures 

specified in paragraph (e)(5) of this 

section. 

* * * * * 

(5) As an alternative to the procedures 

in paragraph (e)(4)(i) of this section, an 

owner or operator may elect to use the 

procedures documented in the GRI 

report entitled, ‘‘Atmospheric Rich/Lean 

Method for Determining Glycol 

Dehydrator Emissions’’ (GRI–95/0368.1) 

as inputs for the model GRI– 

GLYCalcTM, Version 3.0 or higher, to 

generate a condenser performance 

curve. 

(f) Compliance demonstration for 

control device performance 

requirements. This paragraph applies to 

the demonstration of compliance with 

the control device performance 

requirements specified in 

§ 63.771(d)(1)(i), (e)(3) and (f)(1). 

Compliance shall be demonstrated using 

the requirements in paragraphs (f)(1) 

through (3) of this section. As an 

alternative, an owner or operator that 

installs a condenser as the control 

device to achieve the requirements 

specified in § 63.771(d)(1)(ii), (e)(3) or 

(f)(1) may demonstrate compliance 

according to paragraph (g) of this 

section. An owner or operator may 

switch between compliance with 

paragraph (f) of this section and 

compliance with paragraph (g) of this 

section only after at least 1 year of 

operation in compliance with the 

selected approach. Notification of such 

a change in the compliance method 

shall be reported in the next Periodic 

Report, as required in § 63.775(e), 

following the change. 

* * * * * 

(2) The owner or operator shall 

calculate the daily average of the 

applicable monitored parameter in 

accordance with § 63.773(d)(4) except 

that the inlet gas flow rate to the control 

device shall not be averaged. 

(3) Compliance with the operating 

parameter limit is achieved when the 

daily average of the monitoring 

parameter value calculated under 

paragraph (f)(2) of this section is either 

equal to or greater than the minimum or 

equal to or less than the maximum 

monitoring value established under 

paragraph (f)(1) of this section. For inlet 

gas flow rate, compliance with the 

operating parameter limit is achieved 

when the value is equal to or less than 

the value established under § 63.772(h). 

(4) 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 and required zero and 

span adjustments), the CMS required in 

§ 63.773(d) must be operated at all times 

the affected source is operating. 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. 

Monitoring system repairs are required 

to be completed in response to 

monitoring system malfunctions and to 

return the monitoring system to 

operation as expeditiously as 

practicable. 

(5) Data recorded during monitoring 

system malfunctions, repairs associated 

with monitoring system malfunctions, 

or required monitoring system quality 

assurance or control activities may not 

be used in calculations used to report 

emissions or operating levels. All the 

data collected during all other required 

data collection periods must be used in 

assessing the operation of the control 

device and associated control system. 

(6) Except for periods of monitoring 

system malfunctions, repairs associated 

with monitoring system malfunctions, 

and required quality monitoring system 

quality assurance or quality control 

activities (including, as applicable, 

system accuracy audits and required 

zero and span adjustments), failure to 

collect required data is a deviation of 

the monitoring requirements. 

(g) Compliance demonstration with 

percent reduction or emission limit 

performance requirements—condensers. 

This paragraph applies to the 

demonstration of compliance with the 

performance requirements specified in 

§ 63.771(d)(1)(ii),(e)(3) or (f)(1) for 

condensers. Compliance shall be 

demonstrated using the procedures in 

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

section. 

(1) The owner or operator shall 

establish a site-specific condenser 

performance curve according to 

§ 63.773(d)(5)(ii). For sources required 

to meet the BTEX limit in accordance 

with § 63.771(e) or (f)(1) the owner or 

operator shall identify the minimum 

percent reduction necessary to meet the 

BTEX limit. 

(2) Compliance with the requirements 

in § 63.771(d)(1)(ii),(e)(3) or (f)(1) shall 

be demonstrated by the procedures in 

paragraphs (g)(2)(i) through (iii) of this 

section. 

* * * * * 

(iii) Except as provided in paragraphs 

(g)(2)(iii)(A) and (B) of this section, at 

the end of each operating day, the 

owner or operator shall calculate the 

365-day average HAP, or BTEX, 

emission reduction, as appropriate, from 

the condenser efficiencies as 

determined in paragraph (g)(2)(ii) of this 

section for the preceding 365 operating 

days. If the owner or operator uses a 

combination of process modifications 

and a condenser in accordance with the 

requirements of § 63.771(e), the 365-day 

average HAP, or BTEX, emission 

reduction shall be calculated using the 

emission reduction achieved through 

process modifications and the 

condenser efficiency as determined in 

paragraph (g)(2)(ii) of this section, both 

for the previous 365 operating days. 

(A) After the compliance dates 

specified in § 63.760(f), an owner or 

operator with less than 120 days of data 

for determining average HAP, or BTEX, 

emission reduction, as appropriate, 

shall calculate the average HAP, or 

BTEX emission reduction, as 

appropriate, for the first 120 days of 

operation after the compliance dates. 

For sources required to meet the overall 

95.0 percent reduction requirement, 

compliance is achieved if the 120-day 

average HAP emission reduction is 

equal to or greater than 90.0 percent. For 

sources required to meet the BTEX limit 

under § 63.765(b)(1)(iii), compliance is 

achieved if the average BTEX emission 

reduction is at least 95.0 percent of the 

required 365-day value identified under 

paragraph (g)(1) of this section (i.e., at 

least 76.0 percent if the 365-day design 

value is 80.0 percent). 

(B) After 120 days and no more than 

364 days of operation after the 


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compliance dates specified in 

§ 63.760(f), the owner or operator shall 

calculate the average HAP emission 

reduction as the HAP emission 

reduction averaged over the number of 

days between the current day and the 

applicable compliance date. For sources 

required to meet the overall 95.0- 

percent reduction requirement, 

compliance with the performance 

requirements is achieved if the average 

HAP emission reduction is equal to or 

greater than 90.0 percent. For sources 

required to meet the BTEX limit under 

§ 63.765(b)(1)(iii), compliance is 

achieved if the average BTEX emission 

reduction is at least 95.0 percent of the 

required 365-day value identified under 

paragraph (g)(1) of this section (i.e., at 

least 76.0 percent if the 365-day design 

value is 80.0 percent). 

(3) If the owner or operator has data 

for 365 days or more of operation, 

compliance is achieved based on the 

applicable criteria in paragraphs (g)(3)(i) 

or (ii) of this section. 

(i) For sources meeting the HAP 

emission reduction specified in 

§ 63.771(d)(1)(ii) or (e)(3) the average 

HAP emission reduction calculated in 

paragraph (g)(2)(iii) of this section is 

equal to or greater than 95.0 percent. 

(ii) For sources required to meet the 

BTEX limit under § 63.771(e)(3) or (f)(1), 

compliance is achieved if the average 

BTEX emission reduction calculated in 

paragraph (g)(2)(iii) of this section is 

equal to or greater than the minimum 

percent reduction identified in 

paragraph (g)(1) of this section. 

* * * * * 

(h) Performance testing for 

combustion control devices— 

manufacturers’ performance test. (1) 

This paragraph applies to the 

performance testing of a combustion 

control device conducted by the device 

manufacturer. The manufacturer shall 

demonstrate that a specific model of 

control device achieves the performance 

requirements in (h)(7) of this section by 

conducting a performance test as 

specified in paragraphs (h)(2) through 

(6) of this section. 

(2) Performance testing shall consist 

of three one-hour (or longer) test runs 

for each of the four following firing rate 

settings making a total of 12 test runs 

per test. Propene (propylene) gas shall 

be used for the testing fuel. All fuel 

analyses shall be performed by an 

independent third-party laboratory (not 

affiliated with the control device 

manufacturer or fuel supplier). 

(i) 90–100 percent of maximum 

design rate (fixed rate). 

(ii) 70–100–70 percent (ramp up, 

ramp down). Begin the test at 70 percent 

of the maximum design rate. Within the 

first 5 minutes, ramp the firing rate to 

100 percent of the maximum design 

rate. Hold at 100 percent for 5 minutes. 

In the 10–15 minute time range, ramp 

back down to 70 percent of the 

maximum design rate. Repeat three 

more times for a total of 60 minutes of 

sampling. 

(iii) 30–70–30 percent (ramp up, ramp 

down). Begin the test at 30 percent of 

the maximum design rate. Within the 

first 5 minutes, ramp the firing rate to 

70 percent of the maximum design rate. 

Hold at 70 percent for 5 minutes. In the 

10–15 minute time range, ramp back 

down to 30 percent of the maximum 

design rate. Repeat three more times for 

a total of 60 minutes of sampling. 

(iv) 0–30–0 percent (ramp up, ramp 

down). Begin the test at 0 percent of the 

maximum design rate. Within the first 5 

minutes, ramp the firing rate to 100 

percent of the maximum design rate. 

Hold at 30 percent for 5 minutes. In the 

10–15 minute time range, ramp back 

down to 0 percent of the maximum 

design rate. Repeat three more times for 

a total of 60 minutes of sampling. 

(3) All models employing multiple 

enclosures shall be tested 

simultaneously and with all burners 

operational. Results shall be reported for 

the each enclosure individually and for 

the average of the emissions from all 

interconnected combustion enclosures/ 

chambers. Control device operating data 

shall be collected continuously 

throughout the performance test using 

an electronic Data Acquisition System 

and strip chart. Data shall be submitted 

with the test report in accordance with 

paragraph (8)(iii) of this section. 

(4) Inlet testing shall be conducted as 

specified in paragraphs (h)(4)(i) through 

(iii) of this section. 

(i) The fuel flow metering system 

shall be located in accordance with 

Method 2A, 40 CFR part 60, appendix 

A–1, (or other approved procedure) to 

measure fuel flow rate at the control 

device inlet location. The fitting for 

filling fuel sample containers shall be 

located a minimum of 8 pipe diameters 

upstream of any inlet fuel flow 

monitoring meter. 

(ii) Inlet flow rate shall be determined 

using Method 2A, 40 CFR part 60, 

appendix A–1. Record the start and stop 

reading for each 60-minute THC test. 

Record the gas pressure and temperature 

at 5-minute intervals throughout each 

60-minute THC test. 

(iii) Inlet fuel sampling shall be 

conducted in accordance with the 

criteria in paragraphs (h)(4)(iii)(A) and 

(B) of this section. 

(A) At the inlet fuel sampling 

location, securely connect a Silonitecoated stainless steel evacuated canister 

fitted with a flow controller sufficient to 

fill the canister over a 1 hour period. 

Filling shall be conducted as specified 

in the following: 

(1) Open the canister sampling valve 

at the beginning of the total 

hydrocarbon (THC) test, and close the 

canister at the end of the THC test. 

(2) Fill one canister for each THC test 

run. 

(3) Label the canisters individually 

and record on a chain of custody form. 

(B) Each fuel sample shall be analyzed 

using the following methods. The 

results shall be included in the test 

report. 

(1) Hydrocarbon compounds 

containing between one and five atoms 

of carbon plus benzene using ASTM 

D1945–03. 

(2) Hydrogen (H2), carbon monoxide 

(CO), carbon dioxide (CO2), nitrogen 

(N2), oxygen (O2) using ASTM D1945– 

03. 

(3) Carbonyl sulfide, carbon disulfide 

plus mercaptans using ASTM D5504. 

(4) Higher heating value using ASTM 

D3588–98 or ASTM D4891–89. 

(5) Outlet testing shall be conducted 

in accordance with the criteria in 

paragraphs (h)(5)(i) through (v) of this 

section. 

(i) Sampling and flowrate measured in 

accordance with the following: 

(A) The outlet sampling location shall 

be a minimum of 4 equivalent stack 

diameters downstream from the highest 

peak flame or any other flow 

disturbance, and a minimum of one 

equivalent stack diameter upstream of 

the exit or any other flow disturbance. 

A minimum of two sample ports shall 

be used. 

(B) Flow rate shall be measured using 

Method 1, 40 CFR part 60, Appendix 1, 

for determining flow measurement 

traverse point location; and Method 2, 

40 CFR part 60, Appendix 1, shall be 

used to measure duct velocity. If low 

flow conditions are encountered (i.e., 

velocity pressure differentials less than 

0.05 inches of water) during the 

performance test, a more sensitive 

manometer shall be used to obtain an 

accurate flow profile. 

(ii) Molecular weight shall be 

determined as specified in paragraphs 

(h)(4)(iii)(B), (h)(5)(ii)(A), and 

(h)(5)(ii)(B) of this section. 

(A) An integrated bag sample shall be 

collected during the Method 4, 40 CFR 

part 60, Appendix A, moisture test. 

Analyze the bag sample using a gas 

chromatograph-thermal conductivity 

detector (GC–TCD) analysis meeting the 

following criteria: 

(1) Collect the integrated sample 

throughout the entire test, and collect 


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representative volumes from each 

traverse location. 

(2) The sampling line shall be purged 

with stack gas before opening the valve 

and beginning to fill the bag. 

(3) The bag contents shall be kneaded 

or otherwise vigorously mixed prior to 

the GC analysis. 

(4) The GC–TCD calibration 

procedure in Method 3C, 40 CFR part 

60, Appendix A, shall be modified by 

using EPAAlt–045 as follows: For the 

initial calibration, triplicate injections of 

any single concentration must agree 

within 5 percent of their mean to be 

valid. The calibration response factor for 

a single concentration re-check must be 

within 10 percent of the original 

calibration response factor for that 

concentration. If this criterion is not 

met, the initial calibration using at least 

three concentration levels shall be 

repeated. 

(B) Report the molecular weight of: 

O2, CO2, methane (CH4), and N2 and 

include in the test report submitted 

under § 63.775(d)(iii). Moisture shall be 

determined using Method 4, 40 CFR 

part 60, Appendix A. Traverse both 

ports with the Method 4, 40 CFR part 

60, Appendix A, sampling train during 

each test run. Ambient air shall not be 

introduced into the Method 3C, 40 CFR 

part 60, Appendix A, integrated bag 

sample during the port change. 

(iii) Carbon monoxide shall be 

determined using Method 10, 40 CFR 

part 60, Appendix A. The test shall be 

run at the same time and with the 

sample points used for the EPA Method 

25A, 40 CFR part 60, Appendix A, 

testing. An instrument range of 0–10 per 

million by volume-dry (ppmvd) shall be 

used. 

(iv) Visible emissions shall be 

determined using Method 22, 40 CFR 

part 60, Appendix A. The test shall be 

performed continuously during each 

test run. A digital color photograph of 

the exhaust point, taken from the 

position of the observer and annotated 

with date and time, will be taken once 

per test run and the four photos 

included in the test report. 

(6) Total hydrocarbons (THC) shall be 

determined as specified by the 

following criteria: 

(i) Conduct THC sampling using 

Method 25A, 40 CFR part 60, Appendix 

A, except the option for locating the 

probe in the center 10 percent of the 

stack shall not be allowed. The THC 

probe must be traversed to 16.7 percent, 

50 percent, and 83.3 percent of the stack 

diameter during the testing. 

(ii) A valid test shall consist of three 

Method 25A, 40 CFR part 60, Appendix 

A, tests, each no less than 60 minutes 

in duration. 

(iii) A 0–10 parts per million by 

volume-wet (ppmvw) (as propane) 

measurement range is preferred; as an 

alternative a 0–30 ppmvw (as carbon) 

measurement range may be used. 

(iv) Calibration gases will be propane 

in air and be certified through EPA 

Protocol 1—‘‘EPA Traceability Protocol 

for Assay and Certification of Gaseous 

Calibration Standards,’’ September 

1997, as amended August 25, 1999, 

EPA–600/R–97/121 (or more recent if 

updated since 1999). 

(v) THC measurements shall be 

reported in terms of ppmvw as propane. 

(vi) THC results shall be corrected to 

3 percent CO2, as measured by Method 

3C, 40 CFR part 60, Appendix A. 

(vii) Subtraction of methane/ethane 

from the THC data is not allowed in 

determining results. 

(7) Performance test criteria: 

(i) The control device model tested 

must meet the criteria in paragraphs 

(h)(7)(i)(A) through (C) of this section: 

(A) Method 22, 40 CFR part 60, 

Appendix A, results under paragraph 

(h)(5)(v) of this section with no 

indication of visible emissions, and 

(B) Average Method 25A, 40 CFR part 

60, Appendix A, results under 

paragraph (h)(6) of this section equal to 

or less than 10.0 ppmvw THC as 

propane corrected to 3.0 percent CO2, 

and 

(C) Average CO emissions determined 

under paragraph (h)(5)(iv) of this section 

equal to or less than 10 parts ppmvd, 

corrected to 3.0 percent CO2. 

(ii) The manufacturer shall determine 

a maximum inlet gas flow rate which 

shall not be exceeded for each control 

device model to achieve the criteria in 

paragraph (h)(7)(i) of this section. 

(iii) A control device meeting the 

criteria in paragraphs (h)(7)(i)(A) 

through (C) of this section will have 

demonstrated a destruction efficiency of 

98.0 percent for HAP regulated under 

this subpart. 

(8) The owner or operator of a 

combustion control device model tested 

under this section shall submit the 

information listed in paragraphs (h)(8)(i) 

through (iii) of this section in the test 

report required under § 63.775(d)(1)(iii). 

(i) Full schematic of the control 

device and dimensions of the device 

components. 

(ii) Design net heating value 

(minimum and maximum) of the device. 

(iii) Test fuel gas flow range (in both 

mass and volume). Include the 

minimum and maximum allowable inlet 

gas flow rate. 

(iv) Air/stream injection/assist ranges, 

if used. 

(v) The test parameter ranges listed in 

paragraphs (h)(8)(v)(A) through (O) of 

this section, as applicable for the tested 

model. 

(A) Fuel gas delivery pressure and 

temperature. 

(B) Fuel gas moisture range. 

(C) Purge gas usage range. 

(D) Condensate (liquid fuel) 

separation range. 

(E) Combustion zone temperature 

range. This is required for all devices 

that measure this parameter. 

(F) Excess combustion air range. 

(G) Flame arrestor(s). 

(H) Burner manifold pressure. 

(I) Pilot flame sensor. 

(J) Pilot flame design fuel and fuel 

usage. 

(K) Tip velocity range. 

(L) Momentum flux ratio. 

(M) Exit temperature range. 

(N) Exit flow rate. 

(O) Wind velocity and direction. 

(vi) The test report shall include all 

calibration quality assurance/quality 

control data, calibration gas values, gas 

cylinder certification, and strip charts 

annotated with test times and 

calibration values. 

(i) Compliance demonstration for 

combustion control devices— 

manufacturers’ performance test. This 

paragraph applies to the demonstration 

of compliance for a combustion control 

device tested under the provisions in 

paragraph (h) of this section. Owners or 

operators shall demonstrate that a 

control device achieves the performance 

requirements of § 63.771(d)(1), (e)(3)(ii) 

or (f)(1), by installing a device tested 

under paragraph (h) of this section and 

complying with the following criteria: 

(1) The inlet gas flow rate shall meet 

the range specified by the manufacturer. 

Flow rate shall be measured as specified 

in § 63.773(d)(3)(i)(H)(1). 

(2) A pilot flame shall be present at all 

times of operation. The pilot flame shall 

be monitored in accordance with 

§ 63.773(d)(3)(i)(H)(2). 

(3) Devices shall be operated with no 

visible emissions, except for periods not 

to exceed a total of 5 minutes during 

any 2 consecutive hours. A visible 

emissions test using Method 22, 40 CFR 

part 60, Appendix A, shall be performed 

monthly. The observation period shall 

be 2 hours and shall be used according 

to Method 22. 

(4) Compliance with the operating 

parameter limit is achieved when the 

following criteria are met: 

(i) The inlet gas flow rate monitored 

under paragraph (i)(1) of this section is 

equal to or below the maximum 

established by the manufacturer; and 

(ii) The pilot flame is present at all 

times; and 

(iii) During the visible emissions test 

performed under paragraph (i)(3) of this 


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section the duration of visible emissions 

does not exceed a total of 5 minutes 

during the observation period. Devices 

failing the visible emissions test shall 

follow the requirements in paragraphs 

(i)(4)(iii)(A) and (B) of this section. 

(A) Following the first failure, the fuel 

nozzle(s) and burner tubes shall be 

replaced. 

(B) If, following replacement of the 

fuel nozzle(s) and burner tubes as 

specified in paragraph (i)(4)(iii)(A), the 

visible emissions test is not passed in 

the next scheduled test, either a 

performance test shall be performed 

under paragraph (e) of this section, or 

the device shall be replaced with 

another control device whose model 

was tested, and meets, the requirements 

in paragraph (h) of this section. 

19. Section 63.773 is amended by: 

a. Adding paragraph (b); 

b. Revising paragraph (d)(1) 

introductory text; 

c. Revising paragraph (d)(1)(ii) and 

adding paragraphs (d)(1)(iii) and (iv); 

d. Revising paragraphs (d)(2)(i) and 

(d)(2)(ii); 

e. Revising paragraphs (d)(3)(i)(A) and 

(B); 

f. Revising paragraphs (d)(3)(i)(D) and 

(E); 

g. Revising paragraphs (d)(3)(i)(F)(1) 

and (2); 

h. Revising paragraph (d)(3)(i)(G); 

i. Adding paragraph (d)(3)(i)(H); 

j. Revising paragraph (d)(4); 

k. Revising paragraph (d)(5)(i); 

l. Revising paragraphs (d)(5)(ii)(A) 

through (C); 

m. Revising paragraphs (d)(6)(ii) and 

(iii); 

n. Adding paragraph (d)(6)(vi); 

o. Revising paragraph (d)(8)(i)(A); and 

p. Revising paragraph (d)(8)(ii) to read 

as follows: 

§ 63.773 Inspection and monitoring 

requirements. 

* * * * * 

(b) The owner or operator of a control 

device whose model was tested under 

§ 63.772(h) shall develop an inspection 

and maintenance plan for each control 

device. At a minimum, the plan shall 

contain the control device 

manufacturer’s recommendations for 

ensuring proper operation of the device. 

Semi-annual inspections shall be 

conducted for each control device with 

maintenance and replacement of control 

device components made in accordance 

with the plan. 

* * * * * 

(d) Control device monitoring 

requirements. (1) For each control 

device, except as provided for in 

paragraph (d)(2) of this section, the 

owner or operator shall install and 

operate a continuous parameter 

monitoring system in accordance with 

the requirements of paragraphs (d)(3) 

through (9) of this section. Owners or 

operators that install and operate a flare 

in accordance with § 63.771(d)(1)(iii) or 

(f)(1)(iii) are exempt from the 

requirements of paragraphs (d)(4) and 

(5) of this section. The continuous 

monitoring system shall be designed 

and operated so that a determination 

can be made on whether the control 

device is achieving the applicable 

performance requirements of 

§ 63.771(d), (e)(3) or (f)(1). Each 

continuous parameter monitoring 

system shall meet the following 

specifications and requirements: 

* * * * * 

(ii) A site-specific monitoring plan 

must be prepared that addresses the 

monitoring system design, data 

collection, and the quality assurance 

and quality control elements outlined in 

paragraph (d) of this section and in 

§ 63.8(d). Each CPMS must be installed, 

calibrated, operated, and maintained in 

accordance with the procedures in your 

approved site-specific monitoring plan. 

Using the process described in 

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

monitoring system quality assurance 

and quality control procedures 

alternative to those specified in 

paragraphs (d)(1)(ii)(A) through (E) of 

this section in your site-specific 

monitoring plan. 

(A) The performance criteria and 

design specifications for the monitoring 

system equipment, including the sample 

interface, detector signal analyzer, and 

data acquisition and calculations; 

(B) Sampling interface (e.g., 

thermocouple) location such that the 

monitoring system will provide 

representative measurements; 

(C) Equipment performance checks, 

system accuracy audits, or other audit 

procedures; 

(D) Ongoing operation and 

maintenance procedures in accordance 

with provisions in § 63.8(c)(1) and 

(c)(3); and 

(E) Ongoing reporting and 

recordkeeping procedures in accordance 

with provisions in § 63.10(c), (e)(1), and 

(e)(2)(i). 

(iii) The owner or operator must 

conduct the CPMS equipment 

performance checks, system accuracy 

audits, or other audit procedures 

specified in the site-specific monitoring 

plan at least once every 12 months. 

(iv) The owner or operator must 

conduct a performance evaluation of 

each CPMS in accordance with the sitespecific monitoring plan. 

(2) * * * 

(i) Except for control devices for small 

glycol dehydration units, a boiler or 

process heater in which all vent streams 

are introduced with the primary fuel or 

is used as the primary fuel; or 

(ii) Except for control devices for 

small glycol dehydration units, a boiler 

or process heater with a design heat 

input capacity equal to or greater than 

44 megawatts. 

(3) * * * 

(i) * * * 

(A) For a thermal vapor incinerator 

that demonstrates during the 

performance test conducted under 

§ 63.772(e) that the combustion zone 

temperature is an accurate indicator of 

performance, a temperature monitoring 

device equipped with a continuous 

recorder. The monitoring device shall 

have a minimum accuracy of ± 1 percent 

of the temperature being monitored in 

degrees C, or ± 2.5 degrees C, whichever 

value is greater. The temperature sensor 

shall be installed at a location 

representative of the combustion zone 

temperature. 

(B) For a catalytic vapor incinerator, 

a temperature monitoring device 

equipped with a continuous recorder. 

The device shall be capable of 

monitoring temperature at two locations 

and have a minimum accuracy of ± 1 

percent of the temperature being 

monitored in degrees C, or ± 2.5 degrees 

C, whichever value is greater. One 

temperature sensor shall be installed in 

the vent stream at the nearest feasible 

point to the catalyst bed inlet and a 

second temperature sensor shall be 

installed in the vent stream at the 

nearest feasible point to the catalyst bed 

outlet. 

* * * * * 

(D) For a boiler or process heater a 

temperature monitoring device 

equipped with a continuous recorder. 

The temperature monitoring device 

shall have a minimum accuracy of ± 1 

percent of the temperature being 

monitored in degrees C, or ± 2.5 degrees 

C, whichever value is greater. The 

temperature sensor shall be installed at 

a location representative of the 

combustion zone temperature. 

(E) For a condenser, a temperature 

monitoring device equipped with a 

continuous recorder. The temperature 

monitoring device shall have a 

minimum accuracy of ± 1 percent of the 

temperature being monitored in degrees 

C, or ± 2.8 degrees C, whichever value 

is greater. The temperature sensor shall 

be installed at a location in the exhaust 

vent stream from the condenser. 

(F) * * * 

(1) A continuous parameter 

monitoring system to measure and 


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Federal Register / Vol. 76, No. 163 / Tuesday, August 23, 2011 / Proposed Rules 52823 

record the average total regeneration 

stream mass flow or volumetric flow 

during each carbon bed regeneration 

cycle. The flow sensor must have a 

measurement sensitivity of 5 percent of 

the flow rate or 10 cubic feet per 

minute, whichever is greater. The 

mechanical connections for leakage 

must be checked at least every month, 

and a visual inspection must be 

performed at least every 3 months of all 

components of the flow CPMS for 

physical and operational integrity and 

all electrical connections for oxidation 

and galvanic corrosion if your flow 

CPMS is not equipped with a redundant 

flow sensor; and 

(2) A continuous parameter 

monitoring system to measure and 

record the average carbon bed 

temperature for the duration of the 

carbon bed steaming cycle and to 

measure the actual carbon bed 

temperature after regeneration and 

within 15 minutes of completing the 

cooling cycle. The temperature 

monitoring device shall have a 

minimum accuracy of ± 1 percent of the 

temperature being monitored in degrees 

C, or ± 2.5 degrees C, whichever value 

is greater. 

(G) For a nonregenerative-type carbon 

adsorption system, the owner or 

operator shall monitor the design carbon 

replacement interval established using a 

performance test performed in 

accordance with § 63.772(e)(3) shall be 

based on the total carbon working 

capacity of the control device and 

source operating schedule. 

(H) For a control device model whose 

model is tested under § 63.772(h): 

(1) A continuous monitoring system 

that measures gas flow rate at the inlet 

to the control device. The monitoring 

instrument shall have an accuracy of 

plus or minus 2 percent or better. 

(2) A heat sensing monitoring device 

equipped with a continuous recorder 

that indicates the continuous ignition of 

the pilot flame. 

* * * * * 

(4) Using the data recorded by the 

monitoring system, except for inlet gas 

flow rate, the owner or operator must 

calculate the daily average value for 

each monitored operating parameter for 

each operating day. If the emissions unit 

operation is continuous, the operating 

day is a 24-hour period. If the emissions 

unit operation is not continuous, the 

operating day is the total number of 

hours of control device operation per 

24-hour period. Valid data points must 

be available for 75 percent of the 

operating hours in an operating day to 

compute the daily average. 

(5) * * * 

(i) The owner or operator shall 

establish a minimum operating 

parameter value or a maximum 

operating parameter value, as 

appropriate for the control device, to 

define the conditions at which the 

control device must be operated to 

continuously achieve the applicable 

performance requirements of 

§ 63.771(d)(1), (e)(3)(ii) or (f)(1). Each 

minimum or maximum operating 

parameter value shall be established as 

follows: 

(A) If the owner or operator conducts 

performance tests in accordance with 

the requirements of § 63.772(e)(3) to 

demonstrate that the control device 

achieves the applicable performance 

requirements specified in § 63.771(d)(1), 

(e)(3)(ii) or (f)(1), then the minimum 

operating parameter value or the 

maximum operating parameter value 

shall be established based on values 

measured during the performance test 

and supplemented, as necessary, by a 

condenser design analysis or control 

device manufacturer recommendations 

or a combination of both. 

(B) If the owner or operator uses a 

condenser design analysis in accordance 

with the requirements of § 63.772(e)(4) 

to demonstrate that the control device 

achieves the applicable performance 

requirements specified in § 63.771(d)(1), 

(e)(3)(ii) or (f)(1), then the minimum 

operating parameter value or the 

maximum operating parameter value 

shall be established based on the 

condenser design analysis and may be 

supplemented by the condenser 

manufacturer’s recommendations. 

(C) If the owner or operator operates 

a control device where the performance 

test requirement was met under 

§ 63.772(h) to demonstrate that the 

control device achieves the applicable 

performance requirements specified in 

§ 63.771(d)(1), (e)(3)(ii) or (f)(1), then the 

maximum inlet gas flow rate shall be 

established based on the performance 

test and supplemented, as necessary, by 

the manufacturer recommendations. 

(ii) * * * 

(A) If the owner or operator conducts 

a performance test in accordance with 

the requirements of § 63.772(e)(3) to 

demonstrate that the condenser achieves 

the applicable performance 

requirements in § 63.771(d)(1), (e)(3)(ii) 

or (f)(1), then the condenser 

performance curve shall be based on 

values measured during the 

performance test and supplemented as 

necessary by control device design 

analysis, or control device 

manufacturer’s recommendations, or a 

combination or both. 

(B) If the owner or operator uses a 

control device design analysis in 

accordance with the requirements of 

§ 63.772(e)(4)(i) to demonstrate that the 

condenser achieves the applicable 

performance requirements specified in 

§ 63.771(d)(1), (e)(3)(ii) or (f)(1), then the 

condenser performance curve shall be 

based on the condenser design analysis 

and may be supplemented by the 

control device manufacturer’s 

recommendations. 

(C) As an alternative to paragraph 

(d)(5)(ii)(B) of this section, the owner or 

operator may elect to use the procedures 

documented in the GRI report entitled, 

‘‘Atmospheric Rich/Lean Method for 

Determining Glycol Dehydrator 

Emissions’’ (GRI–95/0368.1) as inputs 

for the model GRI–GLYCalcTM, Version 

3.0 or higher, to generate a condenser 

performance curve. 

* * * * * 

(6) * * * 

(ii) For sources meeting 

§ 63.771(d)(1)(ii), an excursion occurs 

when the 365-day average condenser 

efficiency calculated according to the 

requirements specified in 

§ 63.772(g)(2)(iii) is less than 95.0 

percent. For sources meeting 

§ 63.771(f)(1), an excursion occurs when 

the 365-day average condenser 

efficiency calculated according to the 

requirements specified in 

§ 63.772(g)(2)(iii) is less than 95.0 

percent of the identified 365-day 

required percent reduction. 

(iii) For sources meeting 

§ 63.771(d)(1)(ii), if an owner or 

operator has less than 365 days of data, 

an excursion occurs when the average 

condenser efficiency calculated 

according to the procedures specified in 

§ 63.772(g)(2)(iii)(A) or (B) is less than 

90.0 percent. For sources meeting 

§ 63.771(d)(1)(ii), an excursion occurs 

when the 365-day average condenser 

efficiency calculated according to the 

requirements specified in 

§ 63.772(g)(2)(iii) is less than the 

identified 365-day required percent 

reduction. 

* * * * * 

(vi) For control device whose model 

is tested under § 63.772(h) an excursion 

occurs when: 

(A) The inlet gas flow rate exceeds the 

maximum established during the test 

conducted under § 63.772(h). 

(B) Failure of the monthly visible 

emissions test conducted under 

§ 63.772(i)(3) occurs. 

* * * * * 

(8) * * * 

(i) * * * 

(A) During a malfunction when the 

affected facility is operated during such 


emcdonald on DSK2BSOYB1PROD with PROPOSALS2
52824 Federal Register / Vol. 76, No. 163 / Tuesday, August 23, 2011 / Proposed Rules 

period in accordance with § 63.6(e)(1); 

or 

* * * * * 

(ii) For each control device, or 

combinations of control devices 

installed on the same emissions unit, 

one excused excursion is allowed per 

semiannual period for any reason. The 

initial semiannual period is the 6-month 

reporting period addressed by the first 

Periodic Report submitted by the owner 

or operator in accordance with 

§ 63.775(e) of this subpart. 

* * * * * 

20. Section 63.774 is amended by: 

a. Revising paragraph (b)(3) 

introductory text; 

b. Removing and reserving paragraph 

(b)(3)(ii); 

c. Revising paragraph (b)(4)(ii) 

introductory text; 

d. Adding paragraph (b)(4)(ii)(C); 

e. Adding paragraph (b)(7)(ix); and 

f. Adding paragraphs (g) through (i) to 

read as follows: 

§ 63.774 Recordkeeping requirements. 

* * * * * 

(b) * * * 

(3) Records specified in § 63.10(c) for 

each monitoring system operated by the 

owner or operator in accordance with 

the requirements of § 63.773(d). 

Notwithstanding the requirements of 

§ 63.10(c), monitoring data recorded 

during periods identified in paragraphs 

(b)(3)(i) through (b)(3)(iv) of this section 

shall not be included in any average or 

percent leak rate computed under this 

subpart. Records shall be kept of the 

times and durations of all such periods 

and any other periods during process or 

control device operation when monitors 

are not operating or failed to collect 

required data. 

* * * * * 

(ii) [Reserved] 

* * * * * 

(4) * * * 

(ii) Records of the daily average value 

of each continuously monitored 

parameter for each operating day 

determined according to the procedures 

specified in § 63.773(d)(4) of this 

subpart, except as specified in 

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

this section. 

* * * * * 

(C) For control device whose model is 

tested under § 63.772(h), the records 

required in paragraph (h) of this section. 

* * * * * 

(7) * * * 

(ix) Records identifying the carbon 

replacement schedule under 

§ 63.771(d)(5) and records of each 

carbon replacement. 

* * * * * 

(g) The owner or operator of an 

affected source subject to this subpart 

shall maintain records of the occurrence 

and duration of each malfunction of 

operation (i.e., process equipment) or 

the air pollution control equipment and 

monitoring equipment. The owner or 

operator shall maintain records of 

actions taken during periods of 

malfunction to minimize emissions in 

accordance with § 63.764(a), including 

corrective actions to restore 

malfunctioning process and air 

pollution control and monitoring 

equipment to its normal or usual 

manner of operation. 

(h) Record the following when using 

a control device whose model is tested 

under § 63.772(h) to comply with 

§ 63.771(d), (e)(3)(ii) and (f)(1): 

(1) All visible emission readings and 

flowrate measurements made during the 

compliance determination required by 

§ 63.772(i); and 

(2) All hourly records and other 

recorded periods when the pilot flame 

is absent. 

(i) The date the semi-annual 

maintenance inspection required under 

§ 63.773(b) is performed. Include a list 

of any modifications or repairs made to 

the control device during the inspection 

and other maintenance performed such 

as cleaning of the fuel nozzles. 

21. Section 63.775 is amended by: 

a. Revising paragraph (b)(1); 

b. Revising paragraph (b)(6); 

c. Removing and reserving paragraph 

(b)(7); 

d. Revising paragraph (c)(1); 

e. Revising paragraph (c)(6); 

f. Revising paragraph (c)(7)(i); 

g. Revising paragraph (d)(1)(i); 

h. Revising paragraph (d)(1)(ii) 

introductory text; 

i. Revising paragraph (d)(5)(ii); 

j. Adding paragraph (d)(5)(iv); 

k. Revising paragraph (d)(11); 

l. Adding paragraphs (d)(13) and 

(d)(14); 

m. Revising paragraphs (e)(2) 

introductory text, (e)(2)(ii)(B) and (C); 

n. Adding paragraphs (e)(2)(ii)(E) and 

(F); 

o. Adding paragraphs (e)(2)(xi) 

through (xiii); and 

p. Adding paragraph (g) to read as 

follows: 

§ 63.775 Reporting requirements. 

* * * * * 

(b) * * * 

(1) The initial notifications required 

for existing affected sources under 

§ 63.9(b)(2) shall be submitted as 

provided in paragraphs (b)(1)(i) and (ii) 

of this section. 

(i) Except as otherwise provided in 

paragraph (ii), the initial notifications 

shall be submitted by 1 year after an 

affected source becomes subject to the 

provisions of this subpart or by June 17, 

2000, whichever is later. Affected 

sources that are major sources on or 

before June 17, 2000 and plan to be area 

sources by June 17, 2002 shall include 

in this notification a brief, nonbinding 

description of a schedule for the 

action(s) that are planned to achieve 

area source status. 

(ii) An affected source identified 

under § 63.760(f)(7) or (9) shall submit 

an initial notification required for 

existing affected sources under 

§ 63.9(b)(2) within 1 year after the 

affected source becomes subject to the 

provisions of this subpart or by one year 

after publication of the final rule in the 

Federal Register, whichever is later. An 

affected source identified under 

§ 63.760(f)(7) or (9) that plans to be an 

area source by three years after 

publication of the final rule in the 

Federal Register, shall include in this 

notification a brief, nonbinding 

description of a schedule for the 

action(s) that are planned to achieve 

area source status. 

* * * * * 

(6) If there was a malfunction during 

the reporting period, the Periodic Report 

specified in paragraph (e) of this section 

shall include the number, duration, and 

a brief description for each type of 

malfunction which occurred during the 

reporting period and which caused or 

may have caused any applicable 

emission limitation to be exceeded. The 

report must also include a description of 

actions taken by an owner or operator 

during a malfunction of an affected 

source to minimize emissions in 

accordance with § 63.764(j), including 

actions taken to correct a malfunction. 

(7) [Reserved] 

* * * * * 

(c) * * * 

(1) The initial notifications required 

under § 63.9(b)(2) not later than January 

3, 2008. In addition to submitting your 

initial notification to the addressees 

specified under § 63.9(a), you must also 

submit a copy of the initial notification 

to the EPA’s Office of Air Quality 

Planning and Standards. Send your 

notification via e-mail to Oil and Gas 

Sector@epa.gov or via U.S. mail or other 

mail delivery service to U.S. EPA, 

Sector Policies and Programs Division/ 

Fuels and Incineration Group (E143– 

01), Attn: Oil and Gas Project Leader, 

Research Triangle Park, NC 27711. 

* * * * * 

(6) If there was a malfunction during 

the reporting period, the Periodic Report 

specified in paragraph (e) of this section 

shall include the number, duration, and 


emcdonald on DSK2BSOYB1PROD with PROPOSALS2
Federal Register / Vol. 76, No. 163 / Tuesday, August 23, 2011 / Proposed Rules 52825 

a brief description for each type of 

malfunction which occurred during the 

reporting period and which caused or 

may have caused any applicable 

emission limitation to be exceeded. The 

report must also include a description of 

actions taken by an owner or operator 

during a malfunction of an affected 

source to minimize emissions in 

accordance with § 63.764(j), including 

actions taken to correct a malfunction. 

(7) * * * 

(i) Documentation of the source’s 

location relative to the nearest UA plus 

offset and UC boundaries. This 

information shall include the latitude 

and longitude of the affected source; 

whether the source is located in an 

urban cluster with 10,000 people or 

more; the distance in miles to the 

nearest urbanized area boundary if the 

source is not located in an urban cluster 

with 10,000 people or more; and the 

name of the nearest urban cluster with 

10,000 people or more and nearest 

urbanized area. 

* * * * * 

(d) * * * 

(1) * * * 

(i) The condenser design analysis 

documentation specified in 

§ 63.772(e)(4) of this subpart, if the 

owner or operator elects to prepare a 

design analysis. 

(ii) If the owner or operator is 

required to conduct a performance test, 

the performance test results including 

the information specified in paragraphs 

(d)(1)(ii)(A) and (B) of this section. 

Results of a performance test conducted 

prior to the compliance date of this 

subpart can be used provided that the 

test was conducted using the methods 

specified in § 63.772(e)(3) and that the 

test conditions are representative of 

current operating conditions. If the 

owner or operator operates a 

combustion control device model tested 

under § 63.772(h), an electronic copy of 

the performance test results shall be 

submitted via e-mail to Oil and Gas 

PT@EPA.GOV. 

* * * * * 

(5) * * * 

(ii) An explanation of the rationale for 

why the owner or operator selected each 

of the operating parameter values 

established in § 63.773(d)(5). This 

explanation shall include any data and 

calculations used to develop the value 

and a description of why the chosen 

value indicates that the control device is 

operating in accordance with the 

applicable requirements of 

§ 63.771(d)(1), (e)(3)(ii) or (f)(1). 

* * * * * 

(iv) For each carbon adsorber, the 

predetermined carbon replacement 

schedule as required in § 63.771(d)(5)(i). 

* * * * * 

(11) The owner or operator shall 

submit the analysis prepared under 

§ 63.771(e)(2) to demonstrate the 

conditions by which the facility will be 

operated to achieve the HAP emission 

reduction of 95.0 percent, or the BTEX 

limit in § 63.765(b)(1)(iii), through 

process modifications or a combination 

of process modifications and one or 

more control devices. 

* * * * * 

(13) If the owner or operator installs 

a combustion control device model 

tested under the procedures in 

§ 63.772(h), the data listed under 

§ 63.772(h)(8). 

(14) For each combustion control 

device model tested under § 63.772(h), 

the information listed in paragraphs 

(d)(14)(i) through (vi) of this section. 

(i) Name, address and telephone 

number of the control device 

manufacturer. 

(ii) Control device model number. 

(iii) Control device serial number. 

(iv) Date of control device 

certification test. 

(v) Manufacturer’s HAP destruction 

efficiency rating. 

(vi) Control device operating 

parameters, maximum allowable inlet 

gas flowrate. 

(e) * * * 

(2) The owner or operator shall 

include the information specified in 

paragraphs (e)(2)(i) through (xiii) of this 

section, as applicable. 

* * * * * 

(ii) * * * 

(B) For each excursion caused when 

the 365-day average condenser control 

efficiency is less than the value 

specified in § 63.773(d)(6)(ii), the report 

must include the 365-day average values 

of the condenser control efficiency, and 

the date and duration of the period that 

the excursion occurred. 

(C) For each excursion caused when 

condenser control efficiency is less than 

the value specified in § 63.773(d)(6)(iii), 

the report must include the average 

values of the condenser control 

efficiency, and the date and duration of 

the period that the excursion occurred. 

* * * * * 

(E) For each excursion caused when 

the maximum inlet gas flow rate 

identified under § 63.772(h) is 

exceeded, the report must include the 

values of the inlet gas identified and the 

date and duration of the period that the 

excursion occurred. 

(F) For each excursion caused when 

visible emissions determined under 

§ 63.772(i) exceed the maximum 

allowable duration, the report must 

include the date and duration of the 

period that the excursion occurred. 

* * * * * 

(xi) The results of any periodic test as 

required in § 63.772(e)(3) conducted 

during the reporting period. 

(xii) For each carbon adsorber used to 

meet the control device requirements of 

§ 63.771(d)(1), records of each carbon 

replacement that occurred during the 

reporting period. 

(xiii) For combustion control device 

inspections conducted in accordance 

with § 63.773(b) the records specified in 

§ 63.774(i). 

* * * * * 

(g) Electronic reporting. (1) As of 

January 1, 2012 and within 60 days after 

the date of completing each 

performance test, as defined in § 63.2 

and as required in this subpart, you 

must submit performance test data, 

except opacity data, electronically to the 

EPA’s Central Data Exchange (CDX) by 

using the Electronic Reporting Tool 

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

ert/ert tool.html/). Only data collected 

using test methods compatible with ERT 

are subject to this requirement to be 

submitted electronically into the EPA’s 

WebFIRE database. 

(2) All reports required by this 

subpart not subject to the requirements 

in paragraphs (g)(1) of this section must 

be sent to the Administrator at the 

appropriate address listed in § 63.13. If 

acceptable to both the Administrator 

and the owner or operator of a source, 

these reports may be submitted on 

electronic media. The Administrator 

retains the right to require submittal of 

reports subject to paragraph (g)(1) of this 

section in paper format. 

22. Appendix to subpart HH of part 63 

is amended by revising Table 2 to read 

as follows: 

Appendix to Subpart HH of Part 63— 

Tables 

* * * * * 


emcdonald on DSK2BSOYB1PROD with PROPOSALS2
52826 Federal Register / Vol. 76, No. 163 / Tuesday, August 23, 2011 / Proposed Rules 

TABLE 2 TO SUBPART HH OF PART 63—APPLICABILITY OF 40 CFR PART 63 GENERAL PROVISIONS TO SUBPART HH 

General provisions reference Applicable to 

subpart HH Explanation 

§ 63.1(a)(1) ................................................ Yes. 

§ 63.1(a)(2) ................................................ Yes. 

§ 63.1(a)(3) ................................................ Yes. 

§ 63.1(a)(4) ................................................ Yes. 

§ 63.1(a)(5) ................................................ No ................. Section reserved. 

§ 63.1(a)(6) ................................................ Yes. 

§ 63.1(a)(7) through (a)(9) ......................... No ................. Section reserved. 

§ 63.1(a)(10) .............................................. Yes. 

§ 63.1(a)(11) .............................................. Yes. 

§ 63.1(a)(12) .............................................. Yes. 

§ 63.1(b)(1) ................................................ No ................. Subpart HH specifies applicability. 

§ 63.1(b)(2) ................................................ No ................. Section reserved. 

§ 63.1(b)(3) ................................................ Yes. 

§ 63.1(c)(1) ................................................ No ................. Subpart HH specifies applicability. 

§ 63.1(c)(2) ................................................ Yes ................ Subpart HH exempts area sources from the requirement to obtain a Title V permit 

unless otherwise required by law as specified in § 63.760(h). 

§ 63.1(c)(3) and (c)(4) ............................... No ................. Section reserved. 

§ 63.1(c)(5) ................................................ Yes. 

§ 63.1(d) ..................................................... No ................. Section reserved. 

§ 63.1(e) ..................................................... Yes. 

§ 63.2 ......................................................... Yes ................ Except definition of major source is unique for this source category and there are 

additional definitions in subpart HH. 

§ 63.3(a) through (c) .................................. Yes. 

§ 63.4(a)(1) through (a)(2) ......................... Yes. 

§ 63.4(a)(3) through (a)(5) ......................... No ................. Section reserved. 

§ 63.4(b) ..................................................... Yes. 

§ 63.4(c) ..................................................... Yes. 

§ 63.5(a)(1) ................................................ Yes. 

§ 63.5(a)(2) ................................................ Yes. 

§ 63.5(b)(1) ................................................ Yes. 

§ 63.5(b)(2) ................................................ No ................. Section reserved. 

§ 63.5(b)(3) ................................................ Yes. 

§ 63.5(b)(4) ................................................ Yes. 

§ 63.5(b)(5) ................................................ No ................. Section reserved. 

§ 63.5(b)(6) ................................................ Yes. 

§ 63.5(c) ..................................................... No ................. Section reserved. 

§ 63.5(d)(1) ................................................ Yes. 

§ 63.5(d)(2) ................................................ Yes. 

§ 63.5(d)(3) ................................................ Yes. 

§ 63.5(d)(4) ................................................ Yes. 

§ 63.5(e) ..................................................... Yes. 

§ 63.5(f)(1) ................................................. Yes. 

§ 63.5(f)(2) ................................................. Yes. 

§ 63.6(a) ..................................................... Yes. 

§ 63.6(b)(1) ................................................ Yes. 

§ 63.6(b)(2) ................................................ Yes. 

§ 63.6(b)(3) ................................................ Yes. 

§ 63.6(b)(4) ................................................ Yes. 

§ 63.6(b)(5) ................................................ Yes. 

§ 63.6(b)(6) ................................................ No ................. Section reserved. 

§ 63.6(b)(7) ................................................ Yes. 

§ 63.6(c)(1) ................................................ Yes. 

§ 63.6(c)(2) ................................................ Yes. 

§ 63.6(c)(3) through (c)(4) ......................... No ................. Section reserved. 

§ 63.6(c)(5) ................................................ Yes. 

§ 63.6(d) ..................................................... No ................. Section reserved. 

§ 63.6(e) ..................................................... Yes. 

§ 63.6(e)(1)(i) ............................................. No ................. See § 63.764(j) for general duty requirement. 

§ 63.6(e)(1)(ii) ............................................ No. 

§ 63.6(e)(1)(iii) ........................................... Yes. 

§ 63.6(e)(2) ................................................ No ................. Section reserved. 

§ 63.6(e)(3) ................................................ No. 

§ 63.6(f)(1) ................................................. No. 

§ 63.6(f)(2) ................................................. Yes. 

§ 63.6(f)(3) ................................................. Yes. 

§ 63.6(g) ..................................................... Yes. 

§ 63.6(h) ..................................................... No ................. Subpart HH does not contain opacity or visible emission standards. 

§ 63.6(i)(1) through (i)(14) ......................... Yes. 

§ 63.6(i)(15) ............................................... No ................. Section reserved. 

§ 63.6(i)(16) ............................................... Yes. 

§ 63.6(j) ...................................................... Yes. 


emcdonald on DSK2BSOYB1PROD with PROPOSALS2
Federal Register / Vol. 76, No. 163 / Tuesday, August 23, 2011 / Proposed Rules 52827 

TABLE 2 TO SUBPART HH OF PART 63—APPLICABILITY OF 40 CFR PART 63 GENERAL PROVISIONS TO SUBPART HH— 

Continued 

General provisions reference Applicable to 

subpart HH Explanation 

§ 63.7(a)(1) ................................................ Yes. 

§ 63.7(a)(2) ................................................ Yes ................ But the performance test results must be submitted within 180 days after the compliance date. 

§ 63.7(a)(3) ................................................ Yes. 

§ 63.7(b) ..................................................... Yes. 

§ 63.7(c) ..................................................... Yes. 

§ 63.7(d) ..................................................... Yes. 

§ 63.7(e)(1) ................................................ No. 

§ 63.7(e)(2) ................................................ Yes. 

§ 63.7(e)(3) ................................................ Yes. 

§ 63.7(e)(4) ................................................ Yes. 

§ 63.7(f) ...................................................... Yes. 

§ 63.7(g) ..................................................... Yes. 

§ 63.7(h) ..................................................... Yes. 

§ 63.8(a)(1) ................................................ Yes. 

§ 63.8(a)(2) ................................................ Yes. 

§ 63.8(a)(3) ................................................ No ................. Section reserved. 

§ 63.8(a)(4) ................................................ Yes. 

§ 63.8(b)(1) ................................................ Yes. 

§ 63.8(b)(2) ................................................ Yes. 

§ 63.8(b)(3) ................................................ Yes. 

§ 63.8(c)(1) ................................................ No. 

§ 63.8(c)(1)(i) ............................................. No.

§ 63.8(c)(1)(ii) ............................................ Yes. 

§ 63.8(c)(1)(iii) ............................................ Pending. 

§ 63.8(c)(2) ................................................ Yes. 

§ 63.8(c)(3) ................................................ Yes. 

§ 63.8(c)(4) ................................................ Yes. 

§ 63.8(c)(4)(i) ............................................. No ................. Subpart HH does not require continuous opacity monitors. 

§ 63.8(c)(4)(ii) ............................................ Yes. 

§ 63.8(c)(5) through (c)(8) ......................... Yes. 

§ 63.8(d) ..................................................... Yes. 

§ 63.8(d)(3) ................................................ Yes ................ Except for last sentence, which refers to an SSM plan. SSM plans are not required. 

§ 63.8(e) ..................................................... Yes ................ Subpart HH does not specifically require continuous emissions monitor performance evaluation, however, the Administrator can request that one be conducted. 

§ 63.8(f)(1) through (f)(5) ........................... Yes. 

§ 63.8(f)(6) ................................................. Yes. 

§ 63.8(g) ..................................................... No ................. Subpart HH specifies continuous monitoring system data reduction requirements. 

§ 63.9(a) ..................................................... Yes. 

§ 63.9(b)(1) ................................................ Yes. 

§ 63.9(b)(2) ................................................ Yes ................ Existing sources are given 1 year (rather than 120 days) to submit this notification. 

Major and area sources that meet § 63.764(e) do not have to submit initial notifications. 

§ 63.9(b)(3) ................................................ No ................. Section reserved. 

§ 63.9(b)(4) ................................................ Yes. 

§ 63.9(b)(5) ................................................ Yes. 

§ 63.9(c) ..................................................... Yes. 

§ 63.9(d) ..................................................... Yes. 

§ 63.9(e) ..................................................... Yes. 

§ 63.9(f) ...................................................... No ................. Subpart HH does not have opacity or visible emission standards. 

§ 63.9(g)(1) ................................................ Yes. 

§ 63.9(g)(2) ................................................ No ................. Subpart HH does not have opacity or visible emission standards. 

§ 63.9(g)(3) ................................................ Yes. 

§ 63.9(h)(1) through (h)(3) ......................... Yes ................ Area sources located outside UA plus offset and UC boundaries are not required to 

submit notifications of compliance status. 

§ 63.9(h)(4) ................................................ No ................. Section reserved. 

§ 63.9(h)(5) through (h)(6) ......................... Yes. 

§ 63.9(i) ...................................................... Yes. 

§ 63.9(j) ...................................................... Yes. 

§ 63.10(a) ................................................... Yes. 

§ 63.10(b)(1) .............................................. Yes ................ § 63.774(b)(1) requires sources to maintain the most recent 12 months of data onsite and allows offsite storage for the remaining 4 years of data. 

§ 63.10(b)(2) .............................................. Yes. 

§ 63.10(b)(2)(i) ........................................... No .................

§ 63.10(b)(2)(ii) .......................................... No ................. See § 63.774(g) for recordkeeping of occurrence, duration, and actions taken during malfunctions. 

§ 63.10(b)(2)(iii) ......................................... Yes. 

§ 63.10(b)(2)(iv) through (b)(2)(v) .............. No. 

§ 63.10(b)(2)(vi) through (b)(2)(xiv) ........... Yes. 


emcdonald on DSK2BSOYB1PROD with PROPOSALS2
52828 Federal Register / Vol. 76, No. 163 / Tuesday, August 23, 2011 / Proposed Rules 

TABLE 2 TO SUBPART HH OF PART 63—APPLICABILITY OF 40 CFR PART 63 GENERAL PROVISIONS TO SUBPART HH— 

Continued 

General provisions reference Applicable to 

subpart HH Explanation 

§ 63.10(b)(3) .............................................. Yes ................ § 63.774(b)(1) requires sources to maintain the most recent 12 months of data onsite and allows offsite storage for the remaining 4 years of data. 

§ 63.10(c)(1) .............................................. Yes. 

§ 63.10(c)(2) through (c)(4) ....................... No ................. Sections reserved. 

§ 63.10(c)(5) through (8)(c)(8) ................... Yes. 

§ 63.10(c)(9) .............................................. No ................. Section reserved. 

§ 63.10(c)(10) through (11) ....................... No ................. See § 63.774(g) for recordkeeping of malfunctions. 

§ 63.10(c)(12) through (14) ....................... Yes. 

§ 63.10(c)(15) ............................................ No. 

§ 63.10(d)(1) .............................................. Yes. 

§ 63.10(d)(2) .............................................. Yes ................ Area sources located outside UA plus offset and UC boundaries do not have to 

submit performance test reports. 

§ 63.10(d)(3) .............................................. Yes. 

§ 63.10(d)(4) .............................................. Yes. 

§ 63.10(d)(5) .............................................. No ................. See § 63.775(b)(6) or (c)(6) for reporting of malfunctions. 

§ 63.10(e)(1) .............................................. Yes ................ Area sources located outside UA plus offset and UC boundaries are not required to 

submit reports. 

§ 63.10(e)(2) .............................................. Yes ................ Area sources located outside UA plus offset and UC boundaries are not required to 

submit reports. 

§ 63.10(e)(3)(i) ........................................... Yes ................ Subpart HH requires major sources to submit Periodic Reports semi-annually. Area 

sources are required to submit Periodic Reports annually. Area sources located 

outside UA plus offset and UC boundaries are not required to submit reports. 

§ 63.10(e)(3)(i)(A) ...................................... Yes. 

§ 63.10(e)(3)(i)(B) ...................................... Yes. 

§ 63.10(e)(3)(i)(C) ...................................... No ................. Section reserved. 

§ 63.10(e)(3)(ii) through (viii) ..................... Yes. 

§ 63.10(f) .................................................... Yes. 

§ 63.11(a) and (b) ...................................... Yes. 

§ 63.11(c), (d), and (e) ............................... Yes. 

§ 63.12(a) through (c) ................................ Yes. 

§ 63.13(a) through (c) ................................ Yes. 

§ 63.14(a) and (b) ...................................... Yes. 

§ 63.15(a) and (b) ...................................... Yes. 

§ 63.16 ....................................................... Yes. 

Subpart HHH—[Amended] 

23. Section 63.1270 is amended by: 

a. Revising paragraph (a) introductory 

text; 

b. Revising paragraph (a)(4); 

c. Revising paragraphs (d)(1) and 

(d)(2); and 

d. Adding paragraphs (d)(3), (4) and 

(5) to read as follows: 

§ 63.1270 Applicability and designation of 

affected source. 

(a) This subpart applies to owners and 

operators of natural gas transmission 

and storage facilities that transport or 

store natural gas prior to entering the 

pipeline to a local distribution company 

or to a final end user (if there is no local 

distribution company), and that are 

major sources of hazardous air 

pollutants (HAP) emissions as defined 

in § 63.1271. Emissions for major source 

determination purposes can be 

estimated using the maximum natural 

gas throughput calculated in either 

paragraph (a)(1) or (2) of this section 

and paragraphs (a)(3) and (4) of this 

section. As an alternative to calculating 

the maximum natural gas throughput, 

the owner or operator of a new or 

existing source may use the facility 

design maximum natural gas throughput 

to estimate the maximum potential 

emissions. Other means to determine 

the facility’s major source status are 

allowed, provided the information is 

documented and recorded to the 

Administrator’s satisfaction in 

accordance with § 63.10(b)(3). A 

compressor station that transports 

natural gas prior to the point of custody 

transfer or to a natural gas processing 

plant (if present) is not considered a 

part of the natural gas transmission and 

storage source category. A facility that is 

determined to be an area source, but 

subsequently increases its emissions or 

its potential to emit above the major 

source levels (without obtaining and 

complying with other limitations that 

keep its potential to emit HAP below 

major source levels), and becomes a 

major source, must comply thereafter 

with all applicable provisions of this 

subpart starting on the applicable 

compliance date specified in paragraph 

(d) of this section. Nothing in this 

paragraph is intended to preclude a 

source from limiting its potential to emit 

through other appropriate mechanisms 

that may be available through the 

permitting authority. 

* * * * * 

(4) The owner or operator shall 

determine the maximum values for 

other parameters used to calculate 

potential emissions as the maximum 

over the same period for which 

maximum throughput is determined as 

specified in paragraph (a)(1) or (a)(2) of 

this section. These parameters shall be 

based on an annual average or the 

highest single measured value. For 

estimating maximum potential 

emissions from glycol dehydration 

units, the glycol circulation rate used in 

the calculation shall be the unit’s 

maximum rate under its physical and 

operational design consistent with the 

definition of potential to emit in § 63.2. 

* * * * * 

(d) * * * 

(1) Except as specified in paragraphs 

(d)(3) through (5) of this section, the 

owner or operator of an affected source, 

the construction or reconstruction of 

which commenced before February 6, 


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1998, shall achieve compliance with the 

provisions of this subpart no later than 

June 17, 2002 except as provided for in 

§ 63.6(i). The owner or operator of an 

area source, the construction or 

reconstruction of which commenced 

before February 6, 1998, that increases 

its emissions of (or its potential to emit) 

HAP such that the source becomes a 

major source that is subject to this 

subpart shall comply with this subpart 

3 years after becoming a major source. 

(2) Except as specified in paragraphs 

(d)(3) through (5) of this section, the 

owner or operator of an affected source, 

the construction or reconstruction of 

which commences on or after February 

6, 1998, shall achieve compliance with 

the provisions of this subpart 

immediately upon initial startup or June 

17, 1999, whichever date is later. Area 

sources, the construction or 

reconstruction of which commences on 

or after February 6, 1998, that become 

major sources shall comply with the 

provisions of this standard immediately 

upon becoming a major source. 

(3) Each affected small glycol 

dehydration unit, as defined in 

§ 63.1271, located at a major source, that 

commenced construction before August 

23, 2011 must achieve compliance no 

later than 3 years after the date of 

publication of the final rule in the 

Federal Register, except as provided in 

§ 63.6(i). 

(4) Each affected small glycol 

dehydration unit, as defined in 

§ 63.1271, located at a major source, that 

commenced construction on or after 

August 23, 2011 must achieve 

compliance immediately upon initial 

startup or the date of publication of the 

final rule in the Federal Register, 

whichever is later. 

(5) Each large glycol dehydration unit, 

as defined in § 63.1271, that has 

complied with the provisions of this 

subpart prior to August 23, 2011 by 

reducing its benzene emissions to less 

than 0.9 megagrams per year must 

achieve compliance no later than 

90 days after the date of publication of 

the final rule in the Federal Register, 

except as provided in § 63.6(i). 

* * * * * 

24. Section 63.1271 is amended by: 

a. Adding, in alphabetical order, new 

definitions for the terms ‘‘affirmative 

defense,’’ ‘‘BTEX,’’ ‘‘flare,’’ ‘‘large glycol 

dehydration units,’’ ‘‘small glycol 

dehydration units’’; and 

b. Revising the definitions for ‘‘glycol 

dehydration unit baseline operations’’ 

and ‘‘temperature monitoring device’’ to 

read as follows: 

§ 63.1271 Definitions. 

* * * * * 

Affirmative defense means, in the 

context of an enforcement proceeding, a 

response or defense put forward by a 

defendant, regarding which the 

defendant has the burden of proof, and 

the merits of which are independently 

and objectively evaluated in a judicial 

or administrative proceeding. 

* * * * * 

BTEX means benzene, toluene, ethyl 

benzene and xylene. 

* * * * * 

Flare means a thermal oxidation 

system using an open flame (i.e., 

without enclosure). 

* * * * * 

Glycol dehydration unit baseline 

operations means operations 

representative of the large glycol 

dehydration unit operations as of June 

17, 1999 and the small glycol 

dehydration unit operations as of 

August 23, 2011. For the purposes of 

this subpart, for determining the 

percentage of overall HAP emission 

reduction attributable to process 

modifications, glycol dehydration unit 

baseline operations shall be parameter 

values (including, but not limited to, 

glycol circulation rate or glycol-HAP 

absorbency) that represent actual longterm conditions (i.e., at least 1 year). 

Glycol dehydration units in operation 

for less than 1 year shall document that 

the parameter values represent expected 

long-term operating conditions had 

process modifications not been made. 

* * * * * 

Large glycol dehydration unit means a 

glycol dehydration unit with an actual 

annual average natural gas flowrate 

equal to or greater than 283.0 thousand 

standard cubic meters per day and 

actual annual average benzene 

emissions equal to or greater than 0.90 

Mg/yr, determined according to 

§ 63.1282(a). 

* * * * * 

Small glycol dehydration unit means 

a glycol dehydration unit, located at a 

major source, with an actual annual 

average natural gas flowrate less than 

283.0 thousand standard cubic meters 

per day or actual annual average 

benzene emissions less than 0.90 Mg/yr, 

determined according to § 63.1282(a). 

Temperature monitoring device 

means an instrument used to monitor 

temperature and having a minimum 

accuracy of ± 1 percent of the 

temperature being monitored expressed 

in °C, or ± 2.5 °C, whichever is greater. 

The temperature monitoring device may 

measure temperature in degrees 

Fahrenheit or degrees Celsius, or both. 

* * * * * 

25. Section 63.1272 is revised to read 

as follows: 

§ 63.1272 Startups and shutdowns. 

(a) The provisions set forth in this 

subpart shall apply at all times. 

(b) The owner or operator shall not 

shut down items of equipment that are 

required or utilized for compliance with 

the provisions of this subpart during 

times when emissions are being routed 

to such items of equipment, if the 

shutdown would contravene 

requirements of this subpart applicable 

to such items of equipment. This 

paragraph does not apply if the owner 

or operator must shut down the 

equipment to avoid damage due to a 

contemporaneous startup or shutdown 

of the affected source or a portion 

thereof. 

(c) During startups and shutdowns, 

the owner or operator shall implement 

measures to prevent or minimize excess 

emissions to the maximum extent 

practical. 

(d) In response to an action to enforce 

the standards set forth in this subpart, 

you may assert an affirmative defense to 

a claim for civil penalties for 

exceedances of such standards that are 

caused by malfunction, as defined in 

§ 63.2. Appropriate penalties may be 

assessed, however, if you fail to meet 

your burden of proving all the 

requirements in the affirmative defense. 

The affirmative defense shall not be 

available for claims for injunctive relief. 

(1) To establish the affirmative 

defense in any action to enforce such a 

limit, the owner or operator must timely 

meet the notification requirements in 

paragraph (d)(2) of this section, and 

must prove by a preponderance of 

evidence that: 

(i) The excess emissions: 

(A) Were caused by a sudden, 

infrequent, and unavoidable failure of 

air pollution control and monitoring 

equipment, process equipment, or a 

process to operate in a normal or usual 

manner; and 

(B) Could not have been prevented 

through careful planning, proper design 

or better operation and maintenance 

practices; and 

(C) Did not stem from any activity or 

event that could have been foreseen and 

avoided, or planned for; and 

(D) Were not part of a recurring 

pattern indicative of inadequate design, 

operation, or maintenance; and 

(ii) Repairs were made as 

expeditiously as possible when the 

applicable emission limitations were 

being exceeded. Off-shift and overtime 

labor were used, to the extent 

practicable to make these repairs; and 

(iii) The frequency, amount and 

duration of the excess emissions 

(including any bypass) were minimized 


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52830 Federal Register / Vol. 76, No. 163 / Tuesday, August 23, 2011 / Proposed Rules 

to the maximum extent practicable 

during periods of such emissions; and 

(iv) If the excess emissions 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 

(v) All possible steps were taken to 

minimize the impact of the excess 

emissions on ambient air quality, the 

environment, and human health; and 

(vi) All emissions monitoring and 

control systems were kept in operation 

if at all possible, consistent with safety 

and good air pollution control practices; 

and 

(vii) All of the actions in response to 

the excess emissions were documented 

by properly signed, contemporaneous 

operating logs; and 

(viii) At all times, the affected source 

was operated in a manner consistent 

with good practices for minimizing 

emissions; and 

(ix) A written root cause analysis has 

been prepared to determine, correct, and 

eliminate the primary causes of the 

malfunction and the excess emissions 

resulting from the malfunction event at 

issue. The analysis shall also specify, 

using best monitoring methods and 

engineering judgment, the amount of 

excess emissions that were the result of 

the malfunction. 

(2) Notification. The owner or 

operator of the affected source 

experiencing an exceedance of its 

emission limit(s) during a malfunction 

shall notify the Administrator by 

telephone or facsimile transmission as 

soon as possible, but no later than two 

business days after the initial 

occurrence of the malfunction, if it 

wishes to avail itself of an affirmative 

defense to civil penalties for that 

malfunction. The owner or operator 

seeking to assert an affirmative defense 

shall also submit a written report to the 

Administrator within 45 days of the 

initial occurrence of the exceedance of 

the standard in this subpart to 

demonstrate, with all necessary 

supporting documentation, that it has 

met the requirements set forth in 

paragraph (d)(1) of this section. The 

owner or operator may seek an 

extension of this deadline for up to 30 

additional days by submitting a written 

request to the Administrator before the 

expiration of the 45 day period. Until a 

request for an extension has been 

approved by the Administrator, the 

owner or operator is subject to the 

requirement to submit such report 

within 45 days of the initial occurrence 

of the exceedance. 

26. Section 63.1274 is amended by: 

a. Revising paragraph (c) introductory 

text; 

b. Removing and reserving paragraph 

(d); 

c. Revising paragraph (g); and 

d. Adding paragraph (h) to read as 

follows: 

§ 63.1274 General standards. 

* * * * * 

(c) The owner or operator of an 

affected source (i.e., glycol dehydration 

unit) located at an existing or new major 

source of HAP emissions shall comply 

with the requirements in this subpart as 

follows: 

* * * * * 

(d) [Reserved] 

* * * * * 

(g) In all cases where the provisions 

of this subpart require an owner or 

operator to repair leaks by a specified 

time after the leak is detected, it is a 

violation of this standard to fail to take 

action to repair the leak(s) within the 

specified time. If action is taken to 

repair the leak(s) within the specified 

time, failure of that action to 

successfully repair the leak(s) is not a 

violation of this standard. However, if 

the repairs are unsuccessful, and a leak 

is detected, the owner or operator shall 

take further action as required by the 

applicable provisions of this subpart. 

(h) At all times the owner or operator 

must operate and maintain any affected 

source, including associated air 

pollution control equipment and 

monitoring equipment, in a manner 

consistent with safety and good air 

pollution control practices for 

minimizing emissions. Determination of 

whether such operation and 

maintenance procedures are being used 

will be based on information available 

to the Administrator which may 

include, but is not limited to, 

monitoring results, review of operation 

and maintenance procedures, review of 

operation and maintenance records, and 

inspection of the source. 

27. Section 63.1275 is amended by: 

a. Revising paragraph (a); 

b. Revising paragraph (b)(1); 

c. Revising paragraph (c)(2); and 

d. Revising paragraph (c)(3) to read as 

follows: 

§ 63.1275 Glycol dehydration unit process 

vent standards. 

(a) This section applies to each glycol 

dehydration unit subject to this subpart 

that must be controlled for air emissions 

as specified in paragraph (c)(1) of 

§ 63.1274. 

(b) * * * 

(1) For each glycol dehydration unit 

process vent, the owner or operator 

shall control air emissions by either 

paragraph (b)(1)(i) or (b)(1)(iii) of this 

section. 

(i) The owner or operator of a large 

glycol dehydration unit, as defined in 

§ 63.1271, shall connect the process 

vent to a control device or a 

combination of control devices through 

a closed-vent system. The closed-vent 

system shall be designed and operated 

in accordance with the requirements of 

§ 63.1281(c). The control device(s) shall 

be designed and operated in accordance 

with the requirements of § 63.1281(d). 

(ii) [Reserved] 

(iii) You must limit BTEX emissions 

from each small glycol dehydration 

unit, as defined in § 63.1271, to the limit 

determined in Equation 1 of this 

section. The limit must be met in 

accordance with one of the alternatives 

specified in paragraphs (b)(i)(iii)(A) 

through (D) of this section. 


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Where: 

ELBTEX = Unit-specific BTEX emission limit, 

megagrams per year; 

6.42 × 10¥5 = BTEX emission limit, grams 

BTEX/standard cubic meter -ppmv; 

Throughput = Annual average daily natural 

gas throughput, standard cubic meters 

per day 

Ci,BTEX = BTEX concentration of the natural 

gas at the inlet to the glycol dehydration 

unit, ppmv. 

(A) Connect the process vent to a 

control device or combination of control 

devices through a closed-vent system. 

The closed vent system shall be 

designed and operated in accordance 

with the requirements of § 63.1281(c). 

The control device(s) shall be designed 

and operated in accordance with the 

requirements of § 63.1281(f). 

(B) Meet the emissions limit through 

process modifications in accordance 

with the requirements specified in 

§ 63.1281(e). 

(C) Meet the emission limit for each 

small glycol dehydration unit using a 

combination of process modifications 

and one or more control devices through 

the requirements specified in 

paragraphs (b)(1)(iii)(A) and (B) of this 

section. 

(D) Demonstrate that the emissions 

limit is met through actual uncontrolled 

operation of the small glycol 

dehydration unit. Document operational 

parameters in accordance with the 

requirements specified in § 63.1281(e) 

and emissions in accordance with the 

requirements specified in 

§ 63.1282(a)(3). 

* * * * * 

(c) * * * 

(2) The owner or operator shall 

demonstrate, to the Administrator’s 

satisfaction, that the total HAP 

emissions to the atmosphere from the 

large glycol dehydration unit process 

vent are reduced by 95.0 percent 

through process modifications or a 

combination of process modifications 

and one or more control devices, in 

accordance with the requirements 

specified in § 63.1281(e). 

(3) Control of HAP emissions from a 

GCG separator (flash tank) vent is not 

required if the owner or operator 

demonstrates, to the Administrator’s 

satisfaction, that total emissions to the 

atmosphere from the glycol dehydration 

unit process vent are reduced by one of 

the levels specified in paragraph (c)(3)(i) 

or (iii) through the installation and 

operation of controls as specified in 

paragraph (b)(1) of this section. 

(i) For any large glycol dehydration 

unit, HAP emissions are reduced by 

95.0 percent or more. 

(ii) [Reserved] 

(iii) For each small glycol dehydration 

unit, BTEX emissions are reduced to a 

level less than the limit calculated in 

paragraph (b)(1)(iii) of this section. 

28. Section 63.1281 is amended by: 

a. Revising paragraph (c)(1); 

b. Revising the heading of paragraph 

(d). 

c. Adding paragraph (d) introductory 

text; 

d. Revising paragraph (d)(1)(i) 

introductory text; 

e. Revising paragraph (d)(1)(i)(C); 

f. Revising paragraphs (d)(1)(ii) and 

(iii); 

g. Revising paragraph (d)(4)(i); 

h. Revising paragraph (d)(5)(i); 

i. Revising paragraph (e)(2); 

j. Revising paragraph (e)(3) 

introductory text; 

k. Revising paragraph (e)(3)(ii); and 

l. Adding paragraph (f) to read as 

follows: 

§ 63.1281 Control equipment 

requirements. 

* * * * * 

(c) * * * 

(1) The closed-vent system shall route 

all gases, vapors, and fumes emitted 

from the material in an emissions unit 

to a control device that meets the 

requirements specified in paragraph (d) 

of this section. 

* * * * * 

(d) Control device requirements for 

sources except small glycol dehydration 

units. Owners and operators of small 

glycol dehydration units shall comply 

with the control requirements in 

paragraph (f) of this section. 

(1) * * * 

(i) An enclosed combustion device 

(e.g., thermal vapor incinerator, catalytic 

vapor incinerator, boiler, or process 

heater) that is designed and operated in 

accordance with one of the following 

performance requirements: 

* * * * * 

(C) For a control device that can 

demonstrate a uniform combustion zone 

temperature during the performance test 

conducted under § 63.1282(d), operates 

at a minimum temperature of 760 °C. 

* * * * * 

(ii) A vapor recovery device (e.g., 

carbon adsorption system or condenser) 

or other non-destructive control device 

that is designed and operated to reduce 

the mass content of either TOC or total 

HAP in the gases vented to the device 

by 95.0 percent by weight or greater as 

determined in accordance with the 

requirements of § 63.1282(d). 

(iii) A flare, as defined in § 63.1271, 

that is designed and operated in 

accordance with the requirements of 

§ 63.11(b). 

* * * * * 

(4) * * * 

(i) Each control device used to comply 

with this subpart shall be operating at 

all times when gases, vapors, and fumes 

are vented from the emissions unit or 

units through the closed vent system to 

the control device as required under 

§ 63.1275. An owner or operator may 

vent more than one unit to a control 

device used to comply with this 

subpart. 

* * * * * 

(5) * * * 

(i) Following the initial startup of the 

control device, all carbon in the control 

device shall be replaced with fresh 

carbon on a regular, predetermined time 

interval that is no longer than the 

carbon service life established for the 

carbon adsorption system. Records 

identifying the schedule for replacement 

and records of each carbon replacement 

shall be maintained as required in 

§ 63.1284(b)(7)(ix). The schedule for 

replacement shall be submitted with the 

Notification of Compliance Status 

Report as specified in 

§ 63.1285(d)(4)(iv). Each carbon 

replacement must be reported in the 

Periodic Reports as specified in 

§ 63.1285(e)(2)(xi). 

* * * * * 

(e) * * * 

(2) The owner or operator shall 

document, to the Administrator’s 

satisfaction, the conditions for which 

glycol dehydration unit baseline 

operations shall be modified to achieve 

the 95.0 percent overall HAP emission 

reduction, or BTEX limit determined in 

§ 63.1275(b)(1)(iii), as applicable, either 

through process modifications or 

through a combination of process 

modifications and one or more control 

devices. If a combination of process 

modifications and one or more control 

devices are used, the owner or operator 

shall also establish the emission 

reduction to be achieved by the control 

device to achieve an overall HAP 

emission reduction of 95.0 percent for 

the glycol dehydration unit process vent 

or, if applicable, the BTEX limit 

determined in § 63.1275(b)(1)(iii) for the 

small glycol dehydration unit process 

vent. Only modifications in glycol 

dehydration unit operations directly 

related to process changes, including 

but not limited to changes in glycol 

circulation rate or glycol-HAP 

absorbency, shall be allowed. Changes 

in the inlet gas characteristics or natural 

gas throughput rate shall not be 

considered in determining the overall 

emission reduction due to process 

modifications. 

(3) The owner or operator that 

achieves a 95.0 percent HAP emission 

reduction or meets the BTEX limit 


emcdonald on DSK2BSOYB1PROD with PROPOSALS2
52832 Federal Register / Vol. 76, No. 163 / Tuesday, August 23, 2011 / Proposed Rules 

determined in § 63.1275(b)(1)(iii), as 

applicable, using process modifications 

alone shall comply with paragraph 

(e)(3)(i) of this section. The owner or 

operator that achieves a 95.0 percent 

HAP emission reduction or meets the 

BTEX limit determined in 

§ 63.1275(b)(1)(iii), as applicable, using 

a combination of process modifications 

and one or more control devices shall 

comply with paragraphs (e)(3)(i) and 

(e)(3)(ii) of this section. 

* * * * * 

(ii) The owner or operator shall 

comply with the control device 

requirements specified in paragraph (d) 

or (f) of this section, as applicable, 

except that the emission reduction or 

limit achieved shall be the emission 

reduction or limit specified for the 

control device(s) in paragraph (e)(2) of 

this section. 

(f) Control device requirements for 

small glycol dehydration units. (1) The 

control device used to meet BTEX the 

emission limit calculated in 

§ 63.1275(b)(1)(iii) shall be one of the 

control devices specified in paragraphs 

(f)(1)(i) through (iii) of this section. 

(i) An enclosed combustion device 

(e.g., thermal vapor incinerator, catalytic 

vapor incinerator, boiler, or process 

heater) that is designed and operated to 

reduce the mass content of BTEX in the 

gases vented to the device as 

determined in accordance with the 

requirements of § 63.1282(d). If a boiler 

or process heater is used as the control 

device, then the vent stream shall be 

introduced into the flame zone of the 

boiler or process heater; or 

(ii) A vapor recovery device (e.g., 

carbon adsorption system or condenser) 

or other non-destructive control device 

that is designed and operated to reduce 

the mass content of BTEX in the gases 

vented to the device as determined in 

accordance with the requirements of 

§ 63.1282(d); or 

(iii) A flare, as defined in § 63.1271, 

that is designed and operated in 

accordance with the requirements of 

§ 63.11(b). 

(2) The owner or operator shall 

operate each control device in 

accordance with the requirements 

specified in paragraphs (f)(2)(i) and (ii) 

of this section. 

(i) Each control device used to comply 

with this subpart shall be operating at 

all times. An owner or operator may 

vent more than one unit to a control 

device used to comply with this 

subpart. 

(ii) For each control device monitored 

in accordance with the requirements of 

§ 63.1283(d), the owner or operator shall 

demonstrate compliance according to 

the requirements of either § 63.1282(e) 

or (h). 

(3) For each carbon adsorption system 

used as a control device to meet the 

requirements of paragraph (f)(1) of this 

section, the owner or operator shall 

manage the carbon as required under 

(d)(5)(i) and (ii) of this section. 

29. Section 63.1282 is amended by: 

a. Revising paragraph (a) introductory 

text; 

b. Revising paragraph (a)(1)(ii); 

c. Revising paragraph (a)(2); 

d. Adding paragraph (c); 

e. Revising paragraph (d) introductory 

text; 

f. Revising paragraphs (d)(1)(i) 

through (v); 

g. Revising paragraph (d)(2); 

h. Revising paragraph (d)(3) 

introductory text; 

i. Revising paragraph (d)(3)(i)(B); 

j. Revising paragraph (d)(3)(iv)(C)(1); 

k. Adding paragraphs (d)(3)(v) and 

(vi); 

l. Revising paragraph (d)(4) 

introductory text; 

m. Revising paragraph (d)(4)(i); 

n. Revising paragraph (d)(5); 

o. Revising paragraph (e) introductory 

text; 

p. Revising paragraphs (e)(2) and 

(e)(3); 

q. Adding paragraphs (e)(4) through 

(e)(6); 

r. Revising paragraph (f) introductory 

text; 

s. Revising paragraph (f)(1); 

t. Revising paragraph (f)(2) 

introductory text; 

u. Revising paragraph (f)(2)(iii); 

v. Revising paragraph (f)(3); and 

w. Adding paragraphs (g) and (h) to 

read as follows: 

§ 63.1282 Test methods, compliance 

procedures, and compliance 

demonstrations. 

(a) Determination of glycol 

dehydration unit flowrate, benzene 

emissions, or BTEX emissions. The 

procedures of this paragraph shall be 

used by an owner or operator to 

determine glycol dehydration unit 

natural gas flowrate, benzene emissions, 

or BTEX emissions. 

(1) * * * 

(ii) The owner or operator shall 

document, to the Administrator’s 

satisfaction, the actual annual average 

natural gas flowrate to the glycol 

dehydration unit. 

(2) The determination of actual 

average benzene or BTEX emissions 

from a glycol dehydration unit shall be 

made using the procedures of either 

paragraph (a)(2)(i) or (a)(2)(ii) of this 

section. Emissions shall be determined 

either uncontrolled or with federally 

enforceable controls in place. 

(i) The owner or operator shall 

determine actual average benzene or 

BTEX emissions using the model GRI– 

GLYCalcTM, Version 3.0 or higher, and 

the procedures presented in the 

associated GRI–GLYCalcTM Technical 

Reference Manual. Inputs to the model 

shall be representative of actual 

operating conditions of the glycol 

dehydration unit and may be 

determined using the procedures 

documented in the Gas Research 

Institute (GRI) report entitled 

‘‘Atmospheric Rich/Lean Method for 

Determining Glycol Dehydrator 

Emissions’’ (GRI–95/0368.1); or 

(ii) The owner or operator shall 

determine an average mass rate of 

benzene or BTEX emissions in 

kilograms per hour through direct 

measurement by performing three runs 

of Method 18 in 40 CFR part 60, 

appendix A (or an equivalent method), 

and averaging the results of the three 

runs. Annual emissions in kilograms per 

year shall be determined by multiplying 

the mass rate by the number of hours 

the unit is operated per year. This result 

shall be converted to megagrams per 

year. 

* * * * * 

(c) Test procedures and compliance 

demonstrations for small glycol 

dehydration units. This paragraph 

applies to the test procedures for small 

dehydration units. 

(1) If the owner or operator is using 

a control device to comply with the 

emission limit in § 63.1275(b)(1)(iii), the 

requirements of paragraph (d) of this 

section apply. Compliance is 

demonstrated using the methods 

specified in paragraph (e) of this 

section. 

(2) If no control device is used to 

comply with the emission limit in 

§ 63.1275(b)(1)(iii), the owner or 

operator must determine the glycol 

dehydration unit BTEX emissions as 

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

(iii) of this section. Compliance is 

demonstrated if the BTEX emissions 

determined as specified in paragraphs 

(c)(2)(i) through (iii) are less than the 

emission limit calculated using the 

equation in § 63.1275(b)(1)(iii). 

(i) Method 1 or 1A, 40 CFR part 60, 

appendix A, as appropriate, shall be 

used for selection of the sampling sites 

at the outlet of the glycol dehydration 

unit process vent. Any references to 

particulate mentioned in Methods 1 and 

1A do not apply to this section. 

(ii) The gas volumetric flowrate shall 

be determined using Method 2, 2A, 2C, 

or 2D, 40 CFR part 60, appendix A, as 

appropriate. 

(iii) The BTEX emissions from the 

outlet of the glycol dehydration unit 


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process vent shall be determined using 

the procedures specified in paragraph 

(d)(3)(v) of this section. As an 

alternative, the mass rate of BTEX at the 

outlet of the glycol dehydration unit 

process vent may be calculated using 

the model GRI–GLYCalcTM, Version 3.0 

or higher, and the procedures presented 

in the associated GRI–GLYCalcTM

Technical Reference Manual. Inputs to 

the model shall be representative of 

actual operating conditions of the glycol 

dehydration unit and shall be 

determined using the procedures 

documented in the Gas Research 

Institute (GRI) report entitled 

‘‘Atmospheric Rich/Lean Method for 

Determining Glycol Dehydrator 

Emissions’’ (GRI–95/0368.1). When the 

BTEX mass rate is calculated for glycol 

dehydration units using the model GRI– 

GLYCalcTM, all BTEX measured by 

Method 18, 40 CFR part 60, appendix A, 

shall be summed. 

(d) Control device performance test 

procedures. This paragraph applies to 

the performance testing of control 

devices. The owners or operators shall 

demonstrate that a control device 

achieves the performance requirements 

of § 63.1281(d)(1), (e)(3)(ii), or (f)(1) 

using a performance test as specified in 

paragraph (d)(3) of this section. Owners 

or operators using a condenser have the 

option to use a design analysis as 

specified in paragraph (d)(4) of this 

section. The owner or operator may 

elect to use the alternative procedures in 

paragraph (d)(5) of this section for 

performance testing of a condenser used 

to control emissions from a glycol 

dehydration unit process vent. As an 

alternative to conducting a performance 

test under this section for combustion 

control devices, a control device that 

can be demonstrated to meet the 

performance requirements of 

§ 63.1281(d)(1), (e)(3)(ii), or (f)(1) 

through a performance test conducted 

by the manufacturer, as specified in 

paragraph (g) of this section, can be 

used. 

(1) * * * 

(i) Except as specified in paragraph 

(d)(2) of this section, a flare, as defined 

in § 63.1271, that is designed and 

operated in accordance with § 63.11(b); 

(ii) Except for control devices used for 

small glycol dehydration units, a boiler 

or process heater with a design heat 

input capacity of 44 megawatts or 

greater; 

(iii) Except for control devices used 

for small glycol dehydration units, a 

boiler or process heater into which the 

vent stream is introduced with the 

primary fuel or is used as the primary 

fuel; 

(iv) Except for control devices used 

for small glycol dehydration units, a 

boiler or process heater burning 

hazardous waste for which the owner or 

operator has either been issued a final 

permit under 40 CFR part 270 and 

complies with the requirements of 40 

CFR part 266, subpart H, or has certified 

compliance with the interim status 

requirements of 40 CFR part 266, 

subpart H; 

(v) Except for control devices used for 

small glycol dehydration units, a 

hazardous waste incinerator for which 

the owner or operator has been issued 

a final permit under 40 CFR part 270 

and complies with the requirements of 

40 CFR part 264, subpart O, or has 

certified compliance with the interim 

status requirements of 40 CFR part 265, 

subpart O. 

* * * * * 

(2) An owner or operator shall design 

and operate each flare, as defined in 

§ 63.1271, in accordance with the 

requirements specified in § 63.11(b) and 

the compliance determination shall be 

conducted using Method 22 of 40 CFR 

part 60, appendix A, to determine 

visible emissions. 

(3) For a performance test conducted 

to demonstrate that a control device 

meets the requirements of 

§ 63.1281(d)(1), (e)(3)(ii), or (f)(1) the 

owner or operator shall use the test 

methods and procedures specified in 

paragraphs (d)(3)(i) through (v) of this 

section. The initial and periodic 

performance tests shall be conducted 

according to the schedule specified in 

paragraph (d)(3)(vi) of this section. 

(i) * * * 

(B) To determine compliance with the 

enclosed combustion device total HAP 

concentration limit specified in 

§ 63.1281(d)(1)(i)(B), or the BTEX 

emission limit specified in 

§ 63.1275(b)(1)(iii), the sampling site 

shall be located at the outlet of the 

combustion device. 

* * * * * 

(iv) * * * 

(C) * * * 

(1) The emission rate correction factor 

for excess air, integrated sampling and 

analysis procedures of Method 3A or 

3B, 40 CFR part 60, appendix A, shall 

be used to determine the oxygen 

concentration (%O2d). The samples shall 

be taken during the same time that the 

samples are taken for determining TOC 

concentration or total HAP 

concentration. 

* * * * * 

(v) To determine compliance with the 

BTEX emission limit specified in 

§ 63.1281(f)(1) the owner or operator 

shall use one of the following methods: 

Method 18, 40 CFR part 60, appendix A; 

ASTM D6420–99 (2004), as specified in 

§ 63.772(a)(1)(ii); or any other method or 

data that have been validated according 

to the applicable procedures in Method 

301, 40 CFR part 63, appendix A. The 

following procedures shall be used to 

calculate BTEX emissions: 

(A) The minimum sampling time for 

each run shall be 1 hour in which either 

an integrated sample or a minimum of 

four grab samples shall be taken. If grab 

sampling is used, then the samples shall 

be taken at approximately equal 

intervals in time, such as 15-minute 

intervals during the run. 

(B) The mass rate of BTEX (Eo) shall 

be computed using the equations and 

procedures specified in paragraphs 

(d)(3)(v)(B)(1) and (2) of this section. 

(1) The following equation shall be 

used: 

Where: 

Eo = Mass rate of BTEX at the outlet of the 

control device, dry basis, kilogram per 

hour. 

Coj = Concentration of sample component j of 

the gas stream at the outlet of the control 

device, dry basis, parts per million by 

volume. 

Moj = Molecular weight of sample component 

j of the gas stream at the outlet of the 

control device, gram/gram-mole. 

Qo = Flowrate of gas stream at the outlet of 

the control device, dry standard cubic 

meter per minute. 

K2 = Constant, 2.494 × 10¥6 (parts per 

million) (gram-mole per standard cubic 

meter) (kilogram/gram) (minute/hour), 

where standard temperature (gram-mole 

per standard cubic meter) is 20 degrees 

C. 

n = Number of components in sample. 

(2) When the BTEX mass rate is 

calculated, only BTEX compounds 

measured by Method 18, 40 CFR part 

60, appendix A, or ASTM D6420–99 

(2004) as specified in § 63.772(a)(1)(ii), 

shall be summed using the equations in 

paragraph (d)(3)(v)(B)(1) of this section. 

(vi) The owner or operator shall 

conduct performance tests according to 

the schedule specified in paragraphs 

(d)(3)(vi)(A) and (B) of this section. 

(A) An initial performance test shall 

be conducted within 180 days after the 

compliance date that is specified for 

each affected source in § 63.1270(d)(3) 

and (4) except that the initial 

performance test for existing 

combustion control devices at existing 

major sources shall be conducted no 

later than 3 years after the date of 

publication of the final rule in the 

Federal Register. If the owner or 

operator of an existing combustion 


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control device at an existing major 

source chooses to replace such device 

with a control device whose model is 

tested under § 63.1282(g), then the 

newly installed device shall comply 

with all provisions of this subpart no 

later than 3 years after the date of 

publication of the final rule in the 

Federal Register. The performance test 

results shall be submitted in the 

Notification of Compliance Status 

Report as required in § 63.1285(d)(1)(ii). 

(B) Periodic performance tests shall be 

conducted for all control devices 

required to conduct initial performance 

tests except as specified in paragraphs 

(e)(3)(vi)(B)(1) and (2) of this section. 

The first periodic performance test shall 

be conducted no later than 60 months 

after the initial performance test 

required in paragraph (d)(3)(vi)(A) of 

this section. Subsequent periodic 

performance tests shall be conducted at 

intervals no longer than 60 months 

following the previous periodic 

performance test or whenever a source 

desires to establish a new operating 

limit. The periodic performance test 

results must be submitted in the next 

Periodic Report as specified in 

§ 63.1285(e)(2)(x). Combustion control 

devices meeting the criteria in either 

paragraph (e)(3)(vi)(B)(1) or (2) of this 

section are not required to conduct 

periodic performance tests. 

(1) A control device whose model is 

tested under, and meets the criteria of, 

§ 63.1282(g), or 

(2) A combustion control device 

tested under § 63.1282(d) that meets the 

outlet TOC or HAP performance level 

specified in § 63.1281(d)(1)(i)(B) and 

that establishes a correlation between 

firebox or combustion chamber 

temperature and the TOC or HAP 

performance level. 

* * * * * 

(4) For a condenser design analysis 

conducted to meet the requirements of 

§ 63.1281(d)(1), (e)(3)(ii), or (f)(1), the 

owner or operator shall meet the 

requirements specified in paragraphs 

(d)(4)(i) and (d)(4)(ii) of this section. 

Documentation of the design analysis 

shall be submitted as a part of the 

Notification of Compliance Status 

Report as required in § 63.1285(d)(1)(i). 

(i) The condenser design analysis 

shall include an analysis of the vent 

stream composition, constituent 

concentrations, flowrate, relative 

humidity, and temperature, and shall 

establish the design outlet organic 

compound concentration level, design 

average temperature of the condenser 

exhaust vent stream, and the design 

average temperatures of the coolant 

fluid at the condenser inlet and outlet. 

As an alternative to the condenser 

design analysis, an owner or operator 

may elect to use the procedures 

specified in paragraph (d)(5) of this 

section. 

* * * * * 

(5) As an alternative to the procedures 

in paragraph (d)(4)(i) of this section, an 

owner or operator may elect to use the 

procedures documented in the GRI 

report entitled, ‘‘Atmospheric Rich/Lean 

Method for Determining Glycol 

Dehydrator Emissions,’’ (GRI–95/ 

0368.1) as inputs for the model GRI– 

GLYCalcTM, Version 3.0 or higher, to 

generate a condenser performance 

curve. 

(e) Compliance demonstration for 

control devices performance 

requirements. This paragraph applies to 

the demonstration of compliance with 

the control device performance 

requirements specified in 

§ 63.1281(d)(1), (e)(3)(ii), and (f)(1). 

Compliance shall be demonstrated using 

the requirements in paragraphs (e)(1) 

through (3) of this section. As an 

alternative, an owner or operator that 

installs a condenser as the control 

device to achieve the requirements 

specified in § 63.1281(d)(1)(ii), (e)(3)(ii), 

or (f)(1) may demonstrate compliance 

according to paragraph (f) of this 

section. An owner or operator may 

switch between compliance with 

paragraph (e) of this section and 

compliance with paragraph (f) of this 

section only after at least 1 year of 

operation in compliance with the 

selected approach. Notification of such 

a change in the compliance method 

shall be reported in the next Periodic 

Report, as required in § 63.1285(e), 

following the change. 

* * * * * 

(2) The owner or operator shall 

calculate the daily average of the 

applicable monitored parameter in 

accordance with § 63.1283(d)(4) except 

that the inlet gas flowrate to the control 

device shall not be averaged. 

(3) Compliance is achieved when the 

daily average of the monitoring 

parameter value calculated under 

paragraph (e)(2) of this section is either 

equal to or greater than the minimum or 

equal to or less than the maximum 

monitoring value established under 

paragraph (e)(1) of this section. For inlet 

gas flowrate, compliance with the 

operating parameter limit is achieved 

when the value is equal to or less than 

the value established under 

§ 63.1282(g). 

(4) 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 and required zero and 

span adjustments), the CMS required in 

§ 63.1283(d) must be operated at all 

times the affected source is operating. 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. 

Monitoring system repairs are required 

to be completed in response to 

monitoring system malfunctions and to 

return the monitoring system to 

operation as expeditiously as 

practicable. 

(5) Data recorded during monitoring 

system malfunctions, repairs associated 

with monitoring system malfunctions, 

or required monitoring system quality 

assurance or control activities may not 

be used in calculations used to report 

emissions or operating levels. All the 

data collected during all other required 

data collection periods must be used in 

assessing the operation of the control 

device and associated control system. 

(6) Except for periods of monitoring 

system malfunctions, repairs associated 

with monitoring system malfunctions, 

and required quality monitoring system 

quality assurance or quality control 

activities (including, as applicable, 

system accuracy audits and required 

zero and span adjustments), failure to 

collect required data is a deviation of 

the monitoring requirements. 

(f) Compliance demonstration with 

percent reduction or emission limit 

performance requirements—condensers. 

This paragraph applies to the 

demonstration of compliance with the 

performance requirements specified in 

§ 63.1281(d)(1)(ii), (e)(3) or (f)(1) for 

condensers. Compliance shall be 

demonstrated using the procedures in 

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

section. 

(1) The owner or operator shall 

establish a site-specific condenser 

performance curve according to the 

procedures specified in 

§ 63.1283(d)(5)(ii). For sources required 

to meet the BTEX limit in accordance 

with § 63.1281(e) or (f)(1) the owner or 

operator shall identify the minimum 

percent reduction necessary to meet the 

BTEX limit. 

(2) Compliance with the percent 

reduction requirement in 

§ 63.1281(d)(1)(ii), (e)(3), or (f)(1) shall 

be demonstrated by the procedures in 

paragraphs (f)(2)(i) through (iii) of this 

section. 

* * * * * 


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(iii) Except as provided in paragraphs 

(f)(2)(iii)(A), (B), and (D) of this section, 

at the end of each operating day the 

owner or operator shall calculate the 30- 

day average HAP, or BTEX, emission 

reduction, as appropriate, from the 

condenser efficiencies as determined in 

paragraph (f)(2)(ii) of this section for the 

preceding 30 operating days. If the 

owner or operator uses a combination of 

process modifications and a condenser 

in accordance with the requirements of 

§ 63.1281(e), the 30-day average HAP 

emission, or BTEX, emission reduction, 

shall be calculated using the emission 

reduction achieved through process 

modifications and the condenser 

efficiency as determined in paragraph 

(f)(2)(ii) of this section, both for the 

preceding 30 operating days. 

(A) After the compliance date 

specified in § 63.1270(d), an owner or 

operator of a facility that stores natural 

gas that has less than 30 days of data for 

determining the average HAP, or BTEX, 

emission reduction, as appropriate, 

shall calculate the cumulative average at 

the end of the withdrawal season, each 

season, until 30 days of condenser 

operating data are accumulated. For a 

facility that does not store natural gas, 

the owner or operator that has less than 

30 days of data for determining average 

HAP, or BTEX, emission reduction, as 

appropriate, shall calculate the 

cumulative average at the end of the 

calendar year, each year, until 30 days 

of condenser operating data are 

accumulated. 

(B) After the compliance date 

specified in § 63.1270(d), for an owner 

or operator that has less than 30 days of 

data for determining the average HAP, 

or BTEX, emission reduction, as 

appropriate, compliance is achieved if 

the average HAP, or BTEX, emission 

reduction, as appropriate, calculated in 

paragraph (f)(2)(iii)(A) of this section is 

equal to or greater than 95.0 percent. 

* * * * * 

(3) Compliance is achieved based on 

the applicable criteria in paragraphs 

(f)(3)(i) or (ii) of this section. 

(i) For sources meeting the HAP 

emission reduction specified in 

§ 63.1281(d)(1)(ii) or (e)(3) if the average 

HAP emission reduction calculated in 

paragraph (f)(2)(iii) of this section is 

equal to or greater than 95.0 percent. 

(ii) For sources required to meet the 

BTEX limit under § 63.1281(e)(3) or 

(f)(1), compliance is achieved if the 

average BTEX emission reduction 

calculated in paragraph (f)(2)(iii) of this 

section is equal to or greater than the 

minimum percent reduction identified 

in paragraph (f)(1) of this section. 

* * * * * 

(g) Performance testing for 

combustion control devices— 

manufacturers’ performance test. (1) 

This paragraph applies to the 

performance testing of a combustion 

control device conducted by the device 

manufacturer. The manufacturer shall 

demonstrate that a specific model of 

control device achieves the performance 

requirements in (g)(7) of this section by 

conducting a performance test as 

specified in paragraphs (g)(2) through 

(6) of this section. 

(2) Performance testing shall consist 

of three one-hour (or longer) test runs 

for each of the four following firing rate 

settings making a total of 12 test runs 

per test. Propene (propylene) gas shall 

be used for the testing fuel. All fuel 

analyses shall be performed by an 

independent third-party laboratory (not 

affiliated with the control device 

manufacturer or fuel supplier). 

(i) 90–100 percent of maximum 

design rate (fixed rate). 

(ii) 70–100–70 percent (ramp up, 

ramp down). Begin the test at 70 percent 

of the maximum design rate. Within the 

first 5 minutes, ramp the firing rate to 

100 percent of the maximum design 

rate. Hold at 100 percent for 5 minutes. 

In the 10–15 minute time range, ramp 

back down to 70 percent of the 

maximum design rate. Repeat three 

more times for a total of 60 minutes of 

sampling. 

(iii) 30–70–30 percent (ramp up, ramp 

down). Begin the test at 30 percent of 

the maximum design rate. Within the 

first 5 minutes, ramp the firing rate to 

70 percent of the maximum design rate. 

Hold at 70 percent for 5 minutes. In the 

10–15 minute time range, ramp back 

down to 30 percent of the maximum 

design rate. Repeat three more times for 

a total of 60 minutes of sampling. 

(iv) 0–30–0 percent (ramp up, ramp 

down). Begin the test at 0 percent of the 

maximum design rate. Within the first 5 

minutes, ramp the firing rate to 100 

percent of the maximum design rate. 

Hold at 30 percent for 5 minutes. In the 

10–15 minute time range, ramp back 

down to 0 percent of the maximum 

design rate. Repeat three more times for 

a total of 60 minutes of sampling. 

(3) All models employing multiple 

enclosures shall be tested 

simultaneously and with all burners 

operational. Results shall be reported for 

the each enclosure individually and for 

the average of the emissions from all 

interconnected combustion enclosures/ 

chambers. Control device operating data 

shall be collected continuously 

throughout the performance test using 

an electronic Data Acquisition System 

and strip chart. Data shall be submitted 

with the test report in accordance with 

paragraph (g)(8)(iii) of this section. 

(4) Inlet testing shall be conducted as 

specified in paragraphs (g)(4)(i) through 

(iii) of this section. 

(i) The fuel flow metering system 

shall be located in accordance with 

Method 2A, 40 CFR part 60, appendix 

A–1, (or other approved procedure) to 

measure fuel flow rate at the control 

device inlet location. The fitting for 

filling fuel sample containers shall be 

located a minimum of 8 pipe diameters 

upstream of any inlet fuel flow 

monitoring meter. 

(ii) Inlet flow rate shall be determined 

using Method 2A, 40 CFR part 60, 

appendix A–1. Record the start and stop 

reading for each 60-minute THC test. 

Record the gas pressure and temperature 

at 5-minute intervals throughout each 

60-minute THC test. 

(iii) Inlet fuel sampling shall be 

conducted in accordance with the 

criteria in paragraphs (g)(4)(iii)(A) and 

(B) of this section. 

(A) At the inlet fuel sampling 

location, securely connect a Silonitecoated stainless steel evacuated canister 

fitted with a flow controller sufficient to 

fill the canister over a 1 hour period. 

Filling shall be conducted as specified 

in the following: 

(1) Open the canister sampling valve 

at the beginning of the total 

hydrocarbon (THC) test, and close the 

canister at the end of the THC test. 

(2) Fill one canister for each THC test 

run. 

(3) Label the canisters individually 

and record on a chain of custody form. 

(B) Each fuel sample shall be analyzed 

using the following methods. The 

results shall be included in the test 

report. 

(1) Hydrocarbon compounds 

containing between one and five atoms 

of carbon plus benzene using ASTM 

D1945–03. 

(2) Hydrogen (H2), carbon monoxide 

(CO), carbon dioxide (CO2), nitrogen 

(N2), oxygen (O2) using ASTM D1945– 

03. 

(3) Carbonyl sulfide, carbon disulfide 

plus mercaptans using ASTM D5504. 

(4) Higher heating value using ASTM 

D3588–98 or ASTM D4891–89. 

(5) Outlet testing shall be conducted 

in accordance with the criteria in 

paragraphs (g)(5)(i) through (v) of this 

section. 

(i) Sampling and flowrate measured in 

accordance with the following: 

(A) The outlet sampling location shall 

be a minimum of 4 equivalent stack 

diameters downstream from the highest 

peak flame or any other flow 

disturbance, and a minimum of one 

equivalent stack diameter upstream of 


emcdonald on DSK2BSOYB1PROD with PROPOSALS2
52836 Federal Register / Vol. 76, No. 163 / Tuesday, August 23, 2011 / Proposed Rules 

the exit or any other flow disturbance. 

A minimum of two sample ports shall 

be used. 

(B) Flow rate shall be measured using 

Method 1, 40 CFR part 60, Appendix 1, 

for determining flow measurement 

traverse point location; and Method 2, 

40 CFR part 60, Appendix 1, shall be 

used to measure duct velocity. If low 

flow conditions are encountered (i.e., 

velocity pressure differentials less than 

0.05 inches of water) during the 

performance test, a more sensitive 

manometer shall be used to obtain an 

accurate flow profile. 

(ii) Molecular weight shall be 

determined as specified in paragraphs 

(g)(4)(iii)(B), and (g)(5)(ii)(A) and (B) of 

this section. 

(A) An integrated bag sample shall be 

collected during the Method 4, 40 CFR 

part 60, Appendix A, moisture test. 

Analyze the bag sample using a gas 

chromatograph-thermal conductivity 

detector (GC–TCD) analysis meeting the 

following criteria: 

(1) Collect the integrated sample 

throughout the entire test, and collect 

representative volumes from each 

traverse location. 

(2) The sampling line shall be purged 

with stack gas before opening the valve 

and beginning to fill the bag. 

(3) The bag contents shall be kneaded 

or otherwise vigorously mixed prior to 

the GC analysis. 

(4) The GC–TCD calibration 

procedure in Method 3C, 40 CFR part 

60, Appendix A, shall be modified by 

using EPAAlt-045 as follows: For the 

initial calibration, triplicate injections of 

any single concentration must agree 

within 5 percent of their mean to be 

valid. The calibration response factor for 

a single concentration re-check must be 

within 10 percent of the original 

calibration response factor for that 

concentration. If this criterion is not 

met, the initial calibration using at least 

three concentration levels shall be 

repeated. 

(B) Report the molecular weight of: 

O2, CO2, methane (CH4), and N2 and 

include in the test report submitted 

under § 63.775(d)(iii). Moisture shall be 

determined using Method 4, 40 CFR 

part 60, Appendix A. Traverse both 

ports with the Method 4, 40 CFR part 

60, Appendix A, sampling train during 

each test run. Ambient air shall not be 

introduced into the Method 3C, 40 CFR 

part 60, Appendix A, integrated bag 

sample during the port change. 

(iv) Carbon monoxide shall be 

determined using Method 10, 40 CFR 

part 60, Appendix A. The test shall be 

run at the same time and with the 

sample points used for the EPA Method 

25A, 40 CFR part 60, Appendix A, 

testing. An instrument range of 0–10 per 

million by volume-dry (ppmvd) shall be 

used. 

(v) Visible emissions shall be 

determined using Method 22, 40 CFR 

part 60, Appendix A. The test shall be 

performed continuously during each 

test run. A digital color photograph of 

the exhaust point, taken from the 

position of the observer and annotated 

with date and time, will be taken once 

per test run and the four photos 

included in the test report. 

(6) Total hydrocarbons (THC) shall be 

determined as specified by the 

following criteria: 

(i) Conduct THC sampling using 

Method 25A, 40 CFR part 60, Appendix 

A, except the option for locating the 

probe in the center 10 percent of the 

stack shall not be allowed. The THC 

probe must be traversed to 16.7 percent, 

50 percent, and 83.3 percent of the stack 

diameter during the testing. 

(ii) A valid test shall consist of three 

Method 25A, 40 CFR part 60, Appendix 

A, tests, each no less than 60 minutes 

in duration. 

(iii) A 0–10 parts per million by 

volume-wet (ppmvw) (as propane) 

measurement range is preferred; as an 

alternative a 0–30 ppmvw (as carbon) 

measurement range may be used. 

(iv) Calibration gases will be propane 

in air and be certified through EPA 

Protocol 1—‘‘EPA Traceability Protocol 

for Assay and Certification of Gaseous 

Calibration Standards,’’ September 

1997, as amended August 25, 1999, 

EPA–600/R–97/121 (or more recent if 

updated since 1999). 

(v) THC measurements shall be 

reported in terms of ppmvw as propane. 

(vi) THC results shall be corrected to 

3 percent CO2, as measured by Method 

3C, 40 CFR part 60, Appendix A. 

(vii) Subtraction of methane/ethane 

from the THC data is not allowed in 

determining results. 

(7) Performance test criteria: 

(i) The control device model tested 

must meet the criteria in paragraphs 

(g)(7)(i)(A) through (C) of this section: 

(A) Method 22, 40 CFR part 60, 

Appendix A, results under paragraph 

(g)(5)(v) of this section with no 

indication of visible emissions, and 

(B) Average Method 25A, 40 CFR part 

60, Appendix A, results under 

paragraph (g)(6) of this section equal to 

or less than 10.0 ppmvw THC as 

propane corrected to 3.0 percent CO2, 

and 

(C) Average CO emissions determined 

under paragraph (g)(5)(iv) of this section 

equal to or less than 10 parts ppmvd, 

corrected to 3.0 percent CO2. 

(ii) The manufacturer shall determine 

a maximum inlet gas flow rate which 

shall not be exceeded for each control 

device model to achieve the criteria in 

paragraph (g)(7)(i) of this section. 

(iii) A control device meeting the 

criteria in paragraph (g)(7)(i)(A) through 

(C) of this section will have 

demonstrated a destruction efficiency of 

98.0 percent for HAP regulated under 

this subpart. 

(8) The owner or operator of a 

combustion control device model tested 

under this section shall submit the 

information listed in paragraphs (g)(8)(i) 

through (iii) in the test report required 

under § 63.775(d)(1)(iii). 

(i) Full schematic of the control 

device and dimensions of the device 

components. 

(ii) Design net heating value 

(minimum and maximum) of the device. 

(iii) Test fuel gas flow range (in both 

mass and volume). Include the 

minimum and maximum allowable inlet 

gas flow rate. 

(iv) Air/stream injection/assist ranges, 

if used. 

(v) The test parameter ranges listed in 

paragraphs (g)(8)(v)(A) through (O) of 

this section, as applicable for the tested 

model. 

(A) Fuel gas delivery pressure and 

temperature. 

(B) Fuel gas moisture range. 

(C) Purge gas usage range. 

(D) Condensate (liquid fuel) 

separation range. 

(E) Combustion zone temperature 

range. This is required for all devices 

that measure this parameter. 

(F) Excess combustion air range. 

(G) Flame arrestor(s). 

(H) Burner manifold pressure. 

(I) Pilot flame sensor. 

(J) Pilot flame design fuel and fuel 

usage. 

(K) Tip velocity range. 

(L) Momentum flux ratio. 

(M) Exit temperature range. 

(N) Exit flow rate. 

(O) Wind velocity and direction. 

(vi) The test report shall include all 

calibration quality assurance/quality 

control data, calibration gas values, gas 

cylinder certification, and strip charts 

annotated with test times and 

calibration values. 

(h) Compliance demonstration for 

combustion control devices— 

manufacturers’ performance test. This 

paragraph applies to the demonstration 

of compliance for a combustion control 

device tested under the provisions in 

paragraph (g) of this section. Owners or 

operators shall demonstrate that a 

control device achieves the performance 

requirements of § 63.1281(d)(1), (e)(3)(ii) 

or (f)(1), by installing a device tested 

under paragraph (g) of this section and 

complying with the following criteria: 


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(1) The inlet gas flow rate shall meet 

the range specified by the manufacturer. 

Flow rate shall be measured as specified 

in § 63.1283(d)(3)(i)(H)(1). 

(2) A pilot flame shall be present at all 

times of operation. The pilot flame shall 

be monitored in accordance with 

§ 63.1283(d)(3)(i)(H)(2). 

(3) Devices shall be operated with no 

visible emissions, except for periods not 

to exceed a total of 5 minutes during 

any 2 consecutive hours. A visible 

emissions test using Method 22, 40 CFR 

part 60, Appendix A, shall be performed 

monthly. The observation period shall 

be 2 hours and shall be used according 

to Method 22. 

(4) Compliance with the operating 

parameter limit is achieved when the 

following criteria are met: 

(i) The inlet gas flow rate monitored 

under paragraph (h)(1) of this section is 

equal to or below the maximum 

established by the manufacturer; and 

(ii) The pilot flame is present at all 

times; and 

(iii) During the visible emissions test 

performed under paragraph (h)(3) of this 

section the duration of visible emissions 

does not exceed a total of 5 minutes 

during the observation period. Devices 

failing the visible emissions test shall 

follow the requirements in paragraphs 

(h)(4)(iii)(A) and (B) of this section. 

(A) Following the first failure, the fuel 

nozzle(s) and burner tubes shall be 

replaced. 

(B) If, following replacement of the 

fuel nozzle(s) and burner tubes as 

specified in paragraph (h)(4)(iii)(A), the 

visible emissions test is not passed in 

the next scheduled test, either a 

performance test shall be performed 

under paragraph (d) of this section, or 

the device shall be replaced with 

another control device whose model 

was tested, and meets, the requirements 

in paragraph (g) of this section. 

30. Section 63.1283 is amended by: 

a. Adding paragraph (b); 

b. Revising paragraph (d)(1) 

introductory text; 

c. Revising paragraph (d)(1)(ii) and 

adding paragraphs (d)(1)(iii) and (iv); 

d. Revising paragraph (d)(2)(i) and 

(d)(2)(ii); 

e. Revising paragraphs (d)(3)(i)(A) and 

(B); 

f. Revising paragraphs (d)(3)(i)(D) and 

(E); 

g. Revising paragraphs (d)(3)(i)(F)(1) 

and (2); 

h. Revising paragraph (d)(3)(i)(G); 

i. Adding paragraph (d)(3)(i)(H); 

j. Revising paragraph (d)(4); 

k. Revising paragraph (d)(5)(i); 

l. Revising paragraphs (d)(5)(ii)(A) 

through (C); 

m. Revising paragraph (d)(6) 

introductory text; 

n. Revising paragraph (d)(6)(ii); 

o. Adding paragraph (d)(6)(v); 

p. Revising paragraph (d)(8)(i)(A); and 

q. Revising paragraph (d)(8)(ii) to read 

as follows: 

§ 63.1283 Inspection and monitoring 

requirements. 

* * * * * 

(b) The owner or operator of a control 

device whose model was tested under 

63.1282(g) shall develop an inspection 

and maintenance plan for each control 

device. At a minimum, the plan shall 

contain the control device 

manufacturer’s recommendations for 

ensuring proper operation of the device. 

Semi-annual inspections shall be 

conducted for each control device with 

maintenance and replacement of control 

device components made in accordance 

with the plan. 

* * * * * 

(d) Control device monitoring 

requirements. (1) For each control 

device except as provided for in 

paragraph (d)(2) of this section, the 

owner or operator shall install and 

operate a continuous parameter 

monitoring system in accordance with 

the requirements of paragraphs (d)(3) 

through (9) of this section. Owners or 

operators that install and operate a flare 

in accordance with § 63.1281(d)(1)(iii) 

or (f)(1)(iii) are exempt from the 

requirements of paragraphs (d)(4) and 

(5) of this section. The continuous 

monitoring system shall be designed 

and operated so that a determination 

can be made on whether the control 

device is achieving the applicable 

performance requirements of 

§ 63.1281(d), (e)(3), or (f)(1). Each 

continuous parameter monitoring 

system shall meet the following 

specifications and requirements: 

* * * * * 

(ii) A site-specific monitoring plan 

must be prepared that addresses the 

monitoring system design, data 

collection, and the quality assurance 

and quality control elements outlined in 

paragraph (d) of this section and in 

§ 63.8(d). Each CPMS must be installed, 

calibrated, operated, and maintained in 

accordance with the procedures in your 

approved site-specific monitoring plan. 

Using the process described in 

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

monitoring system quality assurance 

and quality control procedures 

alternative to those specified in 

paragraphs (d)(1)(ii)(A) through (E) of 

this section in your site-specific 

monitoring plan. 

(A) The performance criteria and 

design specifications for the monitoring 

system equipment, including the sample 

interface, detector signal analyzer, and 

data acquisition and calculations; 

(B) Sampling interface (e.g., 

thermocouple) location such that the 

monitoring system will provide 

representative measurements; 

(C) Equipment performance checks, 

system accuracy audits, or other audit 

procedures; 

(D) Ongoing operation and 

maintenance procedures in accordance 

with provisions in § 63.8(c)(1) and 

(c)(3); and 

(E) Ongoing reporting and 

recordkeeping procedures in accordance 

with provisions in § 63.10(c), (e)(1), and 

(e)(2)(i). 

(iii) The owner or operator must 

conduct the CPMS equipment 

performance checks, system accuracy 

audits, or other audit procedures 

specified in the site-specific monitoring 

plan at least once every 12 months. 

(iv) The owner or operator must 

conduct a performance evaluation of 

each CPMS in accordance with the sitespecific monitoring plan. 

(2) * * * 

(i) Except for control devices for small 

glycol dehydration units, a boiler or 

process heater in which all vent streams 

are introduced with the primary fuel or 

are used as the primary fuel; 

(ii) Except for control devices for 

small glycol dehydration units, a boiler 

or process heater with a design heat 

input capacity equal to or greater than 

44 megawatts. 

(3) * * * 

(i) * * * 

(A) For a thermal vapor incinerator 

that demonstrates during the 

performance test conducted under 

§ 63.1282(d) that combustion zone 

temperature is an accurate indicator of 

performance, a temperature monitoring 

device equipped with a continuous 

recorder. The monitoring device shall 

have a minimum accuracy of ± 1 percent 

of the temperature being monitored in 

degrees C, or ± 2.5 degrees C, whichever 

value is greater. The temperature sensor 

shall be installed at a location 

representative of the combustion zone 

temperature. 

(B) For a catalytic vapor incinerator, 

a temperature monitoring device 

equipped with a continuous recorder. 

The device shall be capable of 

monitoring temperatures at two 

locations and have a minimum accuracy 

of ± 1 percent of the temperatures being 

monitored in degrees C, or ± 2.5 degrees 

C, whichever value is greater. One 

temperature sensor shall be installed in 

the vent stream at the nearest feasible 

point to the catalyst bed inlet and a 

second temperature sensor shall be 

installed in the vent stream at the 


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52838 Federal Register / Vol. 76, No. 163 / Tuesday, August 23, 2011 / Proposed Rules 

nearest feasible point to the catalyst bed 

outlet. 

* * * * * 

(D) For a boiler or process heater, a 

temperature monitoring device 

equipped with a continuous recorder. 

The temperature monitoring device 

shall have a minimum accuracy of ± 1 

percent of the temperature being 

monitored in degrees C, or ± 2.5 degrees 

C, whichever value is greater. The 

temperature sensor shall be installed at 

a location representative of the 

combustion zone temperature. 

(E) For a condenser, a temperature 

monitoring device equipped with a 

continuous recorder. The temperature 

monitoring device shall have a 

minimum accuracy of ± 1 percent of the 

temperature being monitored in degrees 

C, or ± 2.8 degrees C, whichever value 

is greater. The temperature sensor shall 

be installed at a location in the exhaust 

vent stream from the condenser. 

(F) * * * 

(1) A continuous parameter 

monitoring system to measure and 

record the average total regeneration 

stream mass flow or volumetric flow 

during each carbon bed regeneration 

cycle. The flow sensor must have a 

measurement sensitivity of 5 percent of 

the flow rate or 10 cubic feet per 

minute, whichever is greater. The 

mechanical connections for leakage 

must be checked at least every month, 

and a visual inspection must be 

performed at least every 3 months of all 

components of the flow CPMS for 

physical and operational integrity and 

all electrical connections for oxidation 

and galvanic corrosion if your flow 

CPMS is not equipped with a redundant 

flow sensor; and 

(2) A continuous parameter 

monitoring system to measure and 

record the average carbon bed 

temperature for the duration of the 

carbon bed steaming cycle and to 

measure the actual carbon bed 

temperature after regeneration and 

within 15 minutes of completing the 

cooling cycle. The temperature 

monitoring device shall have a 

minimum accuracy of ± 1 percent of the 

temperature being monitored in degrees 

C, or ± 2.5 degrees C, whichever value 

is greater. 

(G) For a nonregenerative-type carbon 

adsorption system, the owner or 

operator shall monitor the design carbon 

replacement interval established using a 

performance test performed in 

accordance with § 63.1282(d)(3) and 

shall be based on the total carbon 

working capacity of the control device 

and source operating schedule. 

(H) For a control device whose model 

is tested under § 63.1282(g): 

(1) A continuous monitoring system 

that measures gas flow rate at the inlet 

to the control device. The monitoring 

instrument shall have an accuracy of 

plus or minus 2 percent or better. 

(2) A heat sensing monitoring device 

equipped with a continuous recorder 

that indicates the continuous ignition of 

the pilot flame. 

* * * * * 

(4) Using the data recorded by the 

monitoring system, except for inlet gas 

flowrate, the owner or operator must 

calculate the daily average value for 

each monitored operating parameter for 

each operating day. If the emissions unit 

operation is continuous, the operating 

day is a 24-hour period. If the emissions 

unit operation is not continuous, the 

operating day is the total number of 

hours of control device operation per 

24-hour period. Valid data points must 

be available for 75 percent of the 

operating hours in an operating day to 

compute the daily average. 

(5) * * * 

(i) The owner or operator shall 

establish a minimum operating 

parameter value or a maximum 

operating parameter value, as 

appropriate for the control device, to 

define the conditions at which the 

control device must be operated to 

continuously achieve the applicable 

performance requirements of 

§ 63.1281(d)(1), (e)(3)(ii), or (f)(1). Each 

minimum or maximum operating 

parameter value shall be established as 

follows: 

(A) If the owner or operator conducts 

performance tests in accordance with 

the requirements of § 63.1282(d)(3) to 

demonstrate that the control device 

achieves the applicable performance 

requirements specified in 

§ 63.1281(d)(1), (e)(3)(ii), or (f)(1), then 

the minimum operating parameter value 

or the maximum operating parameter 

value shall be established based on 

values measured during the 

performance test and supplemented, as 

necessary, by a condenser design 

analysis or control device 

manufacturer’s recommendations or a 

combination of both. 

(B) If the owner or operator uses a 

condenser design analysis in accordance 

with the requirements of § 63.1282(d)(4) 

to demonstrate that the control device 

achieves the applicable performance 

requirements specified in 

§ 63.1281(d)(1), (e)(3)(ii), or (f)(1), then 

the minimum operating parameter value 

or the maximum operating parameter 

value shall be established based on the 

condenser design analysis and may be 

supplemented by the condenser 

manufacturer’s recommendations. 

(C) If the owner or operator operates 

a control device where the performance 

test requirement was met under 

§ 63.1282(g) to demonstrate that the 

control device achieves the applicable 

performance requirements specified in 

§ 63.1281(d)(1), (e)(3)(ii) or (f)(1), then 

the maximum inlet gas flow rate shall be 

established based on the performance 

test and supplemented, as necessary, by 

the manufacturer recommendations. 

(ii) * * * 

(A) If the owner or operator conducts 

a performance test in accordance with 

the requirements of § 63.1282(d)(3) to 

demonstrate that the condenser achieves 

the applicable performance 

requirements in § 63.1281(d)(1), 

(e)(3)(ii), or (f)(1), then the condenser 

performance curve shall be based on 

values measured during the 

performance test and supplemented as 

necessary by control device design 

analysis, or control device 

manufacturer’s recommendations, or a 

combination or both. 

(B) If the owner or operator uses a 

control device design analysis in 

accordance with the requirements of 

§ 63.1282(d)(4)(i) to demonstrate that 

the condenser achieves the applicable 

performance requirements specified in 

§ 63.1281(d)(1), (e)(3)(ii), or (f)(1), then 

the condenser performance curve shall 

be based on the condenser design 

analysis and may be supplemented by 

the control device manufacturer’s 

recommendations. 

(C) As an alternative to paragraph 

(d)(5)(ii)(B) of this section, the owner or 

operator may elect to use the procedures 

documented in the GRI report entitled, 

‘‘Atmospheric Rich/Lean Method for 

Determining Glycol Dehydrator 

Emissions’’ (GRI–95/0368.1) as inputs 

for the model GRI–GLYCalcTM, Version 

3.0 or higher, to generate a condenser 

performance curve. 

(6) An excursion for a given control 

device is determined to have occurred 

when the monitoring data or lack of 

monitoring data result in any one of the 

criteria specified in paragraphs (d)(6)(i) 

through (d)(6)(v) of this section being 

met. When multiple operating 

parameters are monitored for the same 

control device and during the same 

operating day, and more than one of 

these operating parameters meets an 

excursion criterion specified in 

paragraphs (d)(6)(i) through (d)(6)(iv) of 

this section, then a single excursion is 

determined to have occurred for the 

control device for that operating day. 

* * * * * 

(ii) For sources meeting 

§ 63.1281(d)(1)(ii), an excursion occurs 

when average condenser efficiency 


emcdonald on DSK2BSOYB1PROD with PROPOSALS2
Federal Register / Vol. 76, No. 163 / Tuesday, August 23, 2011 / Proposed Rules 52839 

calculated according to the 

requirements specified in 

§ 63.1282(f)(2)(iii) is less than 95.0 

percent, as specified in § 63.1282(f)(3). 

For sources meeting § 63.1281(f)(1), an 

excursion occurs when the 30-day 

average condenser efficiency calculated 

according to the requirements of 

§ 63.1282(f)(2)(iii) is less than the 

identified 30-day required percent 

reduction. 

* * * * * 

(v) For control device whose model is 

tested under § 63.1282(g) an excursion 

occurs when: 

(A) The inlet gas flow rate exceeds the 

maximum established during the test 

conducted under § 63.1282(g). 

(B) Failure of the monthly visible 

emissions test conducted under 

§ 63.1282(h)(3) occurs. 

(8) * * * 

(i) * * * 

(A) During a malfunction when the 

affected facility is operated during such 

period in accordance with § 63.6(e)(1); 

or 

* * * * * 

(ii) For each control device, or 

combinations of control devices, 

installed on the same emissions unit, 

one excused excursion is allowed per 

semiannual period for any reason. The 

initial semiannual period is the 6-month 

reporting period addressed by the first 

Periodic Report submitted by the owner 

or operator in accordance with 

§ 63.1285(e) of this subpart. 

* * * * * 

31. Section 63.1284 is amended by: 

a. Revising paragraph (b)(3) 

introductory text; 

b. Removing and reserving paragraph 

(b)(3)(ii); 

c. Revising paragraph (b)(4)(ii); 

d. Adding paragraph (b)(7)(ix); and 

e. Adding paragraph (f), (g) and (h) to 

read as follows: 

§ 63.1284 Recordkeeping requirements. 

* * * * * 

(b) * * * 

(3) Records specified in § 63.10(c) for 

each monitoring system operated by the 

owner or operator in accordance with 

the requirements of § 63.1283(d). 

Notwithstanding the previous sentence, 

monitoring data recorded during 

periods identified in paragraphs (b)(3)(i) 

through (iv) of this section shall not be 

included in any average or percent leak 

rate computed under this subpart. 

Records shall be kept of the times and 

durations of all such periods and any 

other periods during process or control 

device operation when monitors are not 

operating or failed to collect required 

data. 

* * * * * 

(ii) [Reserved] 

* * * * * 

(4) * * * 

(ii) Records of the daily average value 

of each continuously monitored 

parameter for each operating day 

determined according to the procedures 

specified in § 63.1283(d)(4) of this 

subpart, except as specified in 

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

this section. 

(A) For flares, the records required in 

paragraph (e) of this section. 

(B) For condensers installed to 

comply with § 63.1275, records of the 

annual 30-day rolling average condenser 

efficiency determined under § 63.1282(f) 

shall be kept in addition to the daily 

averages. 

(C) For a control device whose model 

is tested under § 63.1282(g), the records 

required in paragraph (g) of this section. 

* * * * * 

(7) * * * 

(ix) Records identifying the carbon 

replacement schedule under 

§ 63.1281(d)(5) and records of each 

carbon replacement. 

* * * * * 

(f) The owner or operator of an 

affected source subject to this subpart 

shall maintain records of the occurrence 

and duration of each malfunction of 

operation (i.e., process equipment) or 

the air pollution control equipment and 

monitoring equipment. The owner or 

operator shall maintain records of 

actions taken during periods of 

malfunction to minimize emissions in 

accordance with § 63.1274(a), including 

corrective actions to restore 

malfunctioning process and air 

pollution control and monitoring 

equipment to its normal or usual 

manner of operation. 

(g) Record the following when using 

a control device whose model is tested 

under § 63.1282(g) to comply with 

§ 63.1281(d), (e)(3)(ii) and (f)(1): 

(1) All visible emission readings and 

flowrate measurements made during the 

compliance determination required by 

§ 63.1282(h); and 

(2) All hourly records and other 

recorded periods when the pilot flame 

is absent. 

(h) The date the semi-annual 

maintenance inspection required under 

§ 63.1283(b) is performed. Include a list 

of any modifications or repairs made to 

the control device during the inspection 

and other maintenance performed such 

as cleaning of the fuel nozzles. 

32. Section 63.1285 is amended by: 

a. Revising paragraph (b)(1); 

b. Revising paragraph (b)(6); 

c. Removing paragraph (b)(7); 

d. Revising paragraph (d)(1) 

introductory text; 

e. Revising paragraph (d)(1)(i); 

f. Revising paragraph (d)(1)(ii) 

introductory text; 

g. Revising paragraph (d)(2) 

introductory text; 

h. Revising paragraph (d)(4)(ii); 

i. Adding paragraph (d)(4)(iv); 

j. Revising paragraph (d)(10); 

k. Adding paragraphs (d)(11) and 

(d)(12); 

l. Revising paragraph (e)(2) 

introductory text; 

m. Revising paragraph (e)(2)(ii)(B); 

n. Adding paragraphs (e)(2)(ii)(D) and 

(E); 

o. Adding paragraphs (e)(2)(x), (xi) 

and (xii); and 

p. Adding paragraph (g) to read as 

follows: 

§ 63.1285 Reporting requirements. 

* * * * * 

(b) * * * 

(1) The initial notifications required 

for existing affected sources under 

§ 63.9(b)(2) shall be submitted as 

provided in paragraphs (b)(1)(i) and (ii) 

of this section. 

(i) Except as otherwise provided in 

paragraph (b)(1)(ii) of this section, the 

initial notification shall be submitted by 

1 year after an affected source becomes 

subject to the provisions of this subpart 

or by June 17, 2000, whichever is later. 

Affected sources that are major sources 

on or before June 17, 2000 and plan to 

be area sources by June 17, 2002 shall 

include in this notification a brief, 

nonbinding description of a schedule 

for the action(s) that are planned to 

achieve area source status. 

(ii) An affected source identified 

under § 63.1270(d)(3) shall submit an 

initial notification required for existing 

affected sources under § 63.9(b)(2) 

within 1 year after the affected source 

becomes subject to the provisions of this 

subpart or by one year after publication 

of the final rule in the Federal Register, 

whichever is later. An affected source 

identified under § 63.1270(d)(3) that 

plans to be an area source by three years 

after publication of the final rule in the 

Federal Register, shall include in this 

notification a brief, nonbinding 

description of a schedule for the 

action(s) that are planned to achieve 

area source status. 

* * * * * 

(6) If there was a malfunction during 

the reporting period, the Periodic Report 

specified in paragraph (e) of this section 

shall include the number, duration, and 

a brief description for each type of 

malfunction which occurred during the 

reporting period and which caused or 

may have caused any applicable 

emission limitation to be exceeded. The 

report must also include a description of 


emcdonald on DSK2BSOYB1PROD with PROPOSALS2
52840 Federal Register / Vol. 76, No. 163 / Tuesday, August 23, 2011 / Proposed Rules 

actions taken by an owner or operator 

during a malfunction of an affected 

source to minimize emissions in 

accordance with § 63.1274(h), including 

actions taken to correct a malfunction. 

* * * * * 

(d) * * * 

(1) If a closed-vent system and a 

control device other than a flare are 

used to comply with § 63.1274, the 

owner or operator shall submit the 

information in paragraph (d)(1)(iii) of 

this section and the information in 

either paragraph (d)(1)(i) or (ii) of this 

section. 

(i) The condenser design analysis 

documentation specified in 

§ 63.1282(d)(4) of this subpart if the 

owner or operator elects to prepare a 

design analysis; or 

(ii) If the owner or operator is 

required to conduct a performance test, 

the performance test results including 

the information specified in paragraphs 

(d)(1)(ii)(A) and (B) of this section. 

Results of a performance test conducted 

prior to the compliance date of this 

subpart can be used provided that the 

test was conducted using the methods 

specified in § 63.1282(d)(3), and that the 

test conditions are representative of 

current operating conditions. If the 

owner or operator operates a 

combustion control device model tested 

under § 63.1282(g), an electronic copy of 

the performance test results shall be 

submitted via e-mail to 

Oil_and_Gas_PT@EPA.GOV. 

* * * * * 

(2) If a closed-vent system and a flare 

are used to comply with § 63.1274, the 

owner or operator shall submit 

performance test results including the 

information in paragraphs (d)(2)(i) and 

(ii) of this section. The owner or 

operator shall also submit the 

information in paragraph (d)(2)(iii) of 

this section. 

* * * * * 

(4) * * * 

(ii) An explanation of the rationale for 

why the owner or operator selected each 

of the operating parameter values 

established in § 63.1283(d)(5) of this 

subpart. This explanation shall include 

any data and calculations used to 

develop the value, and a description of 

why the chosen value indicates that the 

control device is operating in 

accordance with the applicable 

requirements of § 63.1281(d)(1), 

(e)(3)(ii), or (f)(1). 

* * * * * 

(iv) For each carbon adsorber, the 

predetermined carbon replacement 

schedule as required in 

§ 63.1281(d)(5)(i). 

* * * * * 

(10) The owner or operator shall 

submit the analysis prepared under 

§ 63.1281(e)(2) to demonstrate that the 

conditions by which the facility will be 

operated to achieve the HAP emission 

reduction of 95.0 percent, or the BTEX 

limit in § 63.1275(b)(1)(iii) through 

process modifications or a combination 

of process modifications and one or 

more control devices. 

(11) If the owner or operator installs 

a combustion control device model 

tested under the procedures in 

§ 63.1282(g), the data listed under 

§ 63.1282(g)(8). 

(12) For each combustion control 

device model tested under § 63.1282(g), 

the information listed in paragraphs 

(d)(12)(i) through (vi) of this section. 

(i) Name, address and telephone 

number of the control device 

manufacturer. 

(ii) Control device model number. 

(iii) Control device serial number. 

(iv) Date of control device 

certification test. 

(v) Manufacturer’s HAP destruction 

efficiency rating. 

(vi) Control device operating 

parameters, maximum allowable inlet 

gas flowrate. 

* * * * * 

(e) * * * 

(2) The owner or operator shall 

include the information specified in 

paragraphs (e)(2)(i) through (xii) of this 

section, as applicable. 

* * * * * 

(ii) * * * 

(B) For each excursion caused when 

the 30-day average condenser control 

efficiency is less than the value, as 

specified in § 63.1283(d)(6)(ii), the 

report must include the 30-day average 

values of the condenser control 

efficiency, and the date and duration of 

the period that the excursion occurred. 

* * * * * 

(D) For each excursion caused when 

the maximum inlet gas flow rate 

identified under § 63.1282(g) is 

exceeded, the report must include the 

values of the inlet gas identified and the 

date and duration of the period that the 

excursion occurred. 

(E) For each excursion caused when 

visible emissions determined under 

§ 63.1282(h) exceed the maximum 

allowable duration, the report must 

include the date and duration of the 

period that the excursion occurred. 

* * * * * 

(x) The results of any periodic test as 

required in § 63.1282(d)(3) conducted 

during the reporting period. 

(xi) For each carbon adsorber used to 

meet the control device requirements of 

§ 63.1281(d)(1), records of each carbon 

replacement that occurred during the 

reporting period. 

(xii) For combustion control device 

inspections conducted in accordance 

with § 63.1283(b) the records specified 

in § 63.1284(h). 

* * * * * 

(g) Electronic reporting. (1) As of 

January 1, 2012, and within 60 days 

after the date of completing each 

performance test, as defined in § 63.2 

and as required in this subpart, you 

must submit performance test data, 

except opacity data, electronically to the 

EPA’s Central Data Exchange (CDX) by 

using the Electronic Reporting Tool 

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

ert/ert_tool.html/). Only data collected 

using test methods compatible with ERT 

are subject to this requirement to be 

submitted electronically into the EPA’s 

WebFIRE database. 

(2) All reports required by this 

subpart not subject to the requirements 

in paragraphs (g)(1) of this section must 

be sent to the Administrator at the 

appropriate address listed in § 63.13. If 

acceptable to both the Administrator 

and the owner or operator of a source, 

these reports may be submitted on 

electronic media. The Administrator 

retains the right to require submittal of 

reports subject to paragraph (g)(1) of this 

section in paper format. 

33. Section 63.1287 is amended by 

revising paragraph (a) to read as follows: 

§ 63.1287 Alternative means of emission 

limitation. 

(a) If, in the judgment of the 

Administrator, an alternative means of 

emission limitation will achieve a 

reduction in HAP emissions at least 

equivalent to the reduction in HAP 

emissions from that source achieved 

under the applicable requirements in 

§§ 63.1274 through 63.1281, the 

Administrator will publish a notice in 

the Federal Register permitting the use 

of the alternative means for purposes of 

compliance with that requirement. The 

notice may condition the permission on 

requirements related to the operation 

and maintenance of the alternative 

means. 

* * * * * 

34. Appendix to Subpart HHH of Part 

63—Table is amended by revising Table 

2 to read as follows: 

Appendix to Subpart HHH of Part 63— 

Tables 

* * * * * 


emcdonald on DSK2BSOYB1PROD with PROPOSALS2
Federal Register / Vol. 76, No. 163 / Tuesday, August 23, 2011 / Proposed Rules 52841 

TABLE 2 TO SUBPART HHH OF PART 63—APPLICABILITY OF 40 CFR PART 63 GENERAL PROVISIONS TO SUBPART HHH 

General provisions reference Applicable to 

subpart HHH Explanation 

§ 63.1(a)(1) ................................................ Yes.

§ 63.1(a)(2) ................................................ Yes.

§ 63.1(a)(3) ................................................ Yes.

§ 63.1(a)(4) ................................................ Yes.

§ 63.1(a)(5) ................................................ No ................. Section reserved. 

§ 63.1(a)(6) through (a)(8) ......................... Yes.

§ 63.1(a)(9) ................................................ No ................. Section reserved. 

§ 63.1(a)(10) .............................................. Yes.

§ 63.1(a)(11) .............................................. Yes.

§ 63.1(a)(12) through (a)(14) ..................... Yes.

§ 63.1(b)(1) ................................................ No ................. Subpart HHH specifies applicability. 

§ 63.1(b)(2) ................................................ Yes.

§ 63.1(b)(3) ................................................ No.

§ 63.1(c)(1) ................................................ No ................. Subpart HHH specifies applicability. 

§ 63.1(c)(2) ................................................ No.

§ 63.1(c)(3) ................................................ No ................. Section reserved. 

§ 63.1(c)(4) ................................................ Yes.

§ 63.1(c)(5) ................................................ Yes.

§ 63.1(d) ..................................................... No ................. Section reserved. 

§ 63.1(e) ..................................................... Yes.

§ 63.2 ......................................................... Yes ................ Except definition of major source is unique for this source category and there are 

additional definitions in subpart HHH. 

§ 63.3(a) through (c) .................................. Yes.

§ 63.4(a)(1) through (a)(3) ......................... Yes.

§ 63.4(a)(4) ................................................ No ................. Section reserved. 

§ 63.4(a)(5) ................................................ Yes.

§ 63.4(b) ..................................................... Yes.

§ 63.4(c) ..................................................... Yes.

§ 63.5(a)(1) ................................................ Yes.

§ 63.5(a)(2) ................................................ No ................. Preconstruction review required only for major sources that commence construction 

after promulgation of the standard. 

§ 63.5(b)(1) ................................................ Yes.

§ 63.5(b)(2) ................................................ No ................. Section reserved. 

§ 63.5(b)(3) ................................................ Yes.

§ 63.5(b)(4) ................................................ Yes.

§ 63.5(b)(5) ................................................ Yes.

§ 63.5(b)(6) ................................................ Yes.

§ 63.5(c) ..................................................... No ................. Section reserved. 

§ 63.5(d)(1) ................................................ Yes.

§ 63.5(d)(2) ................................................ Yes.

§ 63.5(d)(3) ................................................ Yes.

§ 63.5(d)(4) ................................................ Yes.

§ 63.5(e) ..................................................... Yes.

§ 63.5(f)(1) ................................................. Yes.

§ 63.5(f)(2) ................................................. Yes.

§ 63.6(a) ..................................................... Yes.

§ 63.6(b)(1) ................................................ Yes.

§ 63.6(b)(2) ................................................ Yes.

§ 63.6(b)(3) ................................................ Yes.

§ 63.6(b)(4) ................................................ Yes.

§ 63.6(b)(5) ................................................ Yes.

§ 63.6(b)(6) ................................................ No ................. Section reserved. 

§ 63.6(b)(7) ................................................ Yes.

§ 63.6(c)(1) ................................................ Yes.

§ 63.6(c)(2) ................................................ Yes.

§ 63.6(c)(3) and (c)(4) ............................... No ................. Section reserved. 

§ 63.6(c)(5) ................................................ Yes.

§ 63.6(d) ..................................................... No ................. Section reserved. 

§ 63.6(e) ..................................................... Yes.

§ 63.6(e) ..................................................... Yes ................ Except as otherwise specified. 

§ 63.6(e)(1)(i) ............................................. No ................. See § 63.1274(h) for general duty requirement. 

§ 63.6(e)(1)(ii) ............................................ No.

§ 63.6(e)(1)(iii) ........................................... Yes.

§ 63.6(e)(2) ................................................ Yes.

§ 63.6(e)(3) ................................................ No.

§ 63.6(f)(1) ................................................. No.

§ 63.6(f)(2) ................................................. Yes.

§ 63.6(f)(3) ................................................. Yes.

§ 63.6(g) ..................................................... Yes.

§ 63.6(h) ..................................................... No ................. Subpart HHH does not contain opacity or visible emission standards. 

§ 63.6(i)(1) through (i)(14) ......................... Yes.


emcdonald on DSK2BSOYB1PROD with PROPOSALS2
52842 Federal Register / Vol. 76, No. 163 / Tuesday, August 23, 2011 / Proposed Rules 

TABLE 2 TO SUBPART HHH OF PART 63—APPLICABILITY OF 40 CFR PART 63 GENERAL PROVISIONS TO SUBPART

HHH—Continued 

General provisions reference Applicable to 

subpart HHH Explanation 

§ 63.6(i)(15) ............................................... No ................. Section reserved. 

§ 63.6(i)(16) ............................................... Yes.

§ 63.6(j) ...................................................... Yes.

§ 63.7(a)(1) ................................................ Yes.

§ 63.7(a)(2) ................................................ Yes ................ But the performance test results must be submitted within 180 days after the compliance date. 

§ 63.7(a)(3) ................................................ Yes.

§ 63.7(b) ..................................................... Yes.

§ 63.7(c) ..................................................... Yes.

§ 63.7(d) ..................................................... Yes.

§ 63.7(e)(1) ................................................ No.

§ 63.7(e)(2) ................................................ Yes.

§ 63.7(e)(3) ................................................ Yes.

§ 63.7(e)(4) ................................................ Yes.

§ 63.7(f) ...................................................... Yes.

§ 63.7(g) ..................................................... Yes.

§ 63.7(h) ..................................................... Yes.

§ 63.8(a)(1) ................................................ Yes.

§ 63.8(a)(2) ................................................ Yes.

§ 63.8(a)(3) ................................................ No ................. Section reserved. 

§ 63.8(a)(4) ................................................ Yes.

§ 63.8(b)(1) ................................................ Yes.

§ 63.8(b)(2) ................................................ Yes.

§ 63.8(b)(3) ................................................ Yes.

§ 63.8(c)(1) ................................................ Yes.

63.8(c)(1)(i) ................................................ No.

§ 63.8(c)(1)(ii) ............................................ Yes.

§ 63.8(c)(1)(iii) ............................................ Pending.

§ 63.8(c)(2) ................................................ Yes.

§ 63.8(c)(3) ................................................ Yes.

§ 63.8(c)(4) ................................................ No.

§ 63.8(c)(5) through (c)(8) ......................... Yes.

§ 63.8(d) ..................................................... Yes.

§ 63.8(d)(3) ................................................ Yes ................ Except for last sentence, which refers to an SSM plan. SSM plans are not required. 

§ 63.8(e) ..................................................... Yes ................ Subpart HHH does not specifically require continuous emissions monitor performance evaluations, however, the Administrator can request that one be conducted. 

§ 63.8(f)(1) through (f)(5) ........................... Yes.

§ 63.8(f)(6) ................................................. No ................. Subpart HHH does not require continuous emissions monitoring. 

§ 63.8(g) ..................................................... No ................. Subpart HHH specifies continuous monitoring system data reduction requirements. 

§ 63.9(a) ..................................................... Yes.

§ 63.9(b)(1) ................................................ Yes.

§ 63.9(b)(2) ................................................ Yes ................ Existing sources are given 1 year (rather than 120 days) to submit this notification. 

§ 63.9(b)(3) ................................................ Yes.

§ 63.9(b)(4) ................................................ Yes.

§ 63.9(b)(5) ................................................ Yes.

§ 63.9(c) ..................................................... Yes.

§ 63.9(d) ..................................................... Yes.

§ 63.9(e) ..................................................... Yes.

§ 63.9(f) ...................................................... No.

§ 63.9(g) ..................................................... Yes.

§ 63.9(h)(1) through (h)(3) ......................... Yes.

§ 63.9(h)(4) ................................................ No ................. Section reserved. 

§ 63.9(h)(5) and (h)(6) ............................... Yes.

§ 63.9(i) ...................................................... Yes.

§ 63.9(j) ...................................................... Yes.

§ 63.10(a) ................................................... Yes.

§ 63.10(b)(1) .............................................. Yes ................ Section 63.1284(b)(1) requires sources to maintain the most recent 12 months of 

data on-site and allows offsite storage for the remaining 4 years of data. 

§ 63.10(b)(2) .............................................. Yes.

§ 63.10(b)(2)(i) ........................................... No.

§ 63.10(b)(2)(ii) .......................................... No ................. See § 63.1284(f) for recordkeeping of occurrence, duration, and actions taken during malfunction. 

§ 63.10(b)(2)(iii) ......................................... Yes.

§ 63.10(b)(2)(iv) through (b)(2)(v) .............. No.

§ 63.10(b)(2)(vi) through (b)(2)(xiv) ........... Yes.

§ 63.10(b)(3) .............................................. No.

§ 63.10(c)(1) .............................................. Yes.

§ 63.10(c)(2) through (c)(4) ....................... No ................. Sections reserved. 

§ 63.10(c)(5) through (c)(8) ....................... Yes.

§ 63.10(c)(9) .............................................. No ................. Section reserved. 


emcdonald on DSK2BSOYB1PROD with PROPOSALS2
Federal Register / Vol. 76, No. 163 / Tuesday, August 23, 2011 / Proposed Rules 52843 

TABLE 2 TO SUBPART HHH OF PART 63—APPLICABILITY OF 40 CFR PART 63 GENERAL PROVISIONS TO SUBPART

HHH—Continued 

General provisions reference Applicable to 

subpart HHH Explanation 

§ 63.10(c)(10) and (c)(11) .......................... No ................. See § 63.1284(f)for recordkeeping of malfunctions 

§ 63.10(c)(12) through (c)(14) ................... Yes.

§ 63.10(c)(15) ............................................ No.

§ 63.10(d)(1) .............................................. Yes.

§ 63.10(d)(2) .............................................. Yes.

§ 63.10(d)(3) .............................................. Yes.

§ 63.10(d)(4) .............................................. Yes.

§ 63.10(d)(5) .............................................. No ................. See § 63.1285(b)(6) for reporting of malfunctions. 

§ 63.10(e)(1) .............................................. Yes.

§ 63.10(e)(2) .............................................. Yes.

§ 63.10(e)(3)(i) ........................................... Yes ................ Subpart HHH requires major sources to submit Periodic Reports semi-annually. 

§ 63.10(e)(3)(i)(A) ...................................... Yes.

§ 63.10(e)(3)(i)(B) ...................................... Yes.

§ 63.10(e)(3)(i)(C) ...................................... No ................. Subpart HHH does not require quarterly reporting for excess emissions. 

§ 63.10(e)(3)(ii) through (e)(3)(viii) ............ Yes.

§ 63.10(f) .................................................... Yes.

§ 63.11(a) and (b) ...................................... Yes.

§ 63.11(c), (d), and (e) ............................... Yes.

§ 63.12(a) through (c) ................................ Yes.

§ 63.13(a) through (c) ................................ Yes.

§ 63.14(a) and (b) ...................................... Yes.

§ 63.15(a) and (b) ...................................... Yes. 

[FR Doc. 2011–19899 Filed 8–22–11; 8:45 am] 

BILLING CODE 6560–50–P 


emcdonald on DSK2BSOYB1PROD with PROPOSALS2