Document ID: EPA-HQ-OAR-2010-0505-0002
Agency: epa
Document Type: Proposed Rule
Title: Oil and Natural Gas Sector: New Source Performance Standards and National Emission Standards for Hazardous Air Pollutants Reviews; Proposed Rule
Posted Date: 2011-08-23T04:00Z

[Federal Register Volume 76, Number 163 (Tuesday, August 23, 2011)]
[Proposed Rules]
[Pages 52738-52843]
From the Federal Register Online via the Government Printing Office [www.gpo.gov]
[FR Doc No: 2011-19899]

[[Page 52737]]

Vol. 76

Tuesday,

No. 163

August 23, 2011

Part II

Environmental Protection Agency

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40 CFR Parts 60 and 63

Oil and Natural Gas Sector: New Source Performance Standards and 
National Emission Standards for Hazardous Air Pollutants Reviews; 
Proposed Rule

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

[[Page 52738]]

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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.

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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?

[[Page 52739]]

    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

[[Page 52740]]

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
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                                      NAICS code   Examples of regulated
              Category                   \1\             entities
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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.
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\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

[[Page 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 
best-controlled 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 best-performing 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

[[Page 52742]]

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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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-in-1 
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

[[Page 52743]]

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.
---------------------------------------------------------------------------

    \2\ Although 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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \3\ On 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.
---------------------------------------------------------------------------

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 sector-based approaches is by reviewing multiple regulatory 
programs together whenever possible, consistent with all

[[Page 52744]]

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 non-associated 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 non-methane 
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,

[[Page 52745]]

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.
---------------------------------------------------------------------------

    \4\ The Notice further states that ``The Administrator may also 
concurrently develop standards for sources which are not on the 
priority list.'' 44 FR at 49225.
---------------------------------------------------------------------------

    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 non-delineation wells, the proposed 
operational standards would require reduced emission completion (REC), 
commonly referred to as ``green completion,'' in combination with pit-
flaring 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

[[Page 52746]]

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 x 
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 x 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 x 
10-\5\ grams BTEX/scm-ppmv and that new affected sources 
meet a BTEX limit of 1.10 x 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

[[Page 52747]]

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.
---------------------------------------------------------------------------

    \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).
---------------------------------------------------------------------------

    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

[[Page 52748]]

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, semi-annual 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://

[[Page 52749]]

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

[[Page 52750]]

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 e-GGRT 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

[[Page 52751]]

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 EPA-approved 
programs will still make case-by-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 pollutant-emitting 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.
---------------------------------------------------------------------------

    \6\ Withdrawal 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.
---------------------------------------------------------------------------

    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 EPA-
approved 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.
---------------------------------------------------------------------------

    \7\ CAA section 502(a) prohibits title V exemption for any major 
source, which is defined in CAA section 501(2) and 40 CFR 70.2.
---------------------------------------------------------------------------

    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 non-

[[Page 52752]]

major sources subject to the Oil and Natural Gas Production NSPS.
---------------------------------------------------------------------------

    \8\ The 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.)
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \9\ The proposed numeric standards for pneumatic controllers 
reflect the use of specific equipment (either non-gas driven device 
or low-bleed device).
---------------------------------------------------------------------------

    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 
semi-annual reporting requirement under title V would not improve 
compliance with

[[Page 52753]]

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 non-major 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

[[Page 52754]]

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 non-major 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 non-major 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

[[Page 52755]]

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.
---------------------------------------------------------------------------

    \10\ Because 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.
---------------------------------------------------------------------------

    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

[[Page 52756]]

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.
---------------------------------------------------------------------------

    \11\ U.S. EPA. Inventory of U.S. Greenhouse Gas Inventory and 
Sinks. 1990-2009. http://www.epa.gov/climatechange/emissions/downloads10/US-GHG-Inventory-2010_ExecutiveSummary.pdf.
---------------------------------------------------------------------------

    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

[[Page 52757]]

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 non-methane 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

[[Page 52758]]

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-
liquid-sand 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 cost-effective on average, they may 
not be for all operators. Nonetheless, EPA is proposing to require an 
operational standard rather than a performance-based 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

[[Page 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 cost-effective. 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 
(non-fractured) 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 cost-effectiveness 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

[[Page 52760]]

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 steady-state 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 gas-driven 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 low-bleed 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 low-bleed controller. Moreover, we believe the collateral 
emissions from electrical power generation needed to run the compressor 
are very low. Finally, non-gas-driven pneumatic controllers avoid 
potentially explosive concentrations of natural gas which can occur as 
a result of normal bleeding from groups of gas-driven pneumatic 
controllers located in close proximity, as they often are at gas 
processing plants. Based on our review described above, we believe that 
a non-gas-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

[[Page 52761]]

unavailable and, therefore, only gas-driven 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 high-bleed 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.

[[Page 52762]]

    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, well-aligned 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 
bronze-metallic 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

[[Page 52763]]

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

[[Page 52764]]

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 on-site, 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

[[Page 52765]]

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 VVa-level LDAR (Option 1) results 
in more VOC reduction than the subpart VV-level 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 cost-effectiveness 
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 cost-effectiveness 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 cost-
effectiveness 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, cost-effectiveness 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\
---------------------------------------------------------------------------

    \13\ Because 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.
---------------------------------------------------------------------------

    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

[[Page 52766]]

$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-by-case 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

[[Page 52767]]

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.

[[Page 52768]]

    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 x 
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 x 10-6 
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. 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

[[Page 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 unit-specific 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 x 10-5 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 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 x 
10-5 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. 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 (m\3\/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

[[Page 52770]]

``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 x 10-3 m\3\/liter with a 
throughput of 79,500 liter/day had HAP emissions of 9.91 Mg/yr, 
including 9.45 Mg/yr of n-hexane.
    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.
---------------------------------------------------------------------------

    \14\ U.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.
---------------------------------------------------------------------------

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 MACT-
Allowable 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 MACT-allowable 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 MACT-allowable 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 dose-response 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,

[[Page 52771]]

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.
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    \15\ U.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).
    \16\ A census block is generally the smallest geographic area 
for which census statistics are tabulated.
---------------------------------------------------------------------------

    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 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 such 
dose-response 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 x 10-\9\ per [mu]g/m\3\) was 
based on better science than the IRIS cancer dose-response value (1.3 x 
10-\5\ per [mu]g/m\3\) 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.
---------------------------------------------------------------------------

    \17\ For 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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \18\ U.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.
    \19\ See the Risk Assessment for Source Categories document 
available in the docket for a list of HAP with a mutagenic mode of 
action.
    \20\ U.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.
    \21\ U.S. EPA. Science Policy Council Cancer Guidelines 
Implementation Workgroup Communication II: Memo from W.H. Farland, 
dated June 14, 2006.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \22\ These 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.
---------------------------------------------------------------------------

    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

[[Page 52772]]

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 dose-response 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, short-term 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, high-priority 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.''
---------------------------------------------------------------------------

    \23\ NAS, 2001. Standing Operating Procedures for Developing 
Acute Exposure Levels for Hazardous Chemicals, page 2.
---------------------------------------------------------------------------

    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/
m\3\) 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.''
---------------------------------------------------------------------------

    \24\ ERP Committee Procedures and Responsibilities. November 1, 
2006. American Industrial Hygiene Association.
---------------------------------------------------------------------------

    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

[[Page 52773]]

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.
---------------------------------------------------------------------------

    \25\ See http://www.tceq.state.tx.us/compliance/field_ops/eer/index.html or docket to access the source of these data.
---------------------------------------------------------------------------

    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 site-specific 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.
---------------------------------------------------------------------------

    \26\ The SAB peer review of RTR Risk Assessment Methodologies is 
available at: http://yosemite.epa.gov/sab/sabproduct.nsf/
4AB3966E263D943A8525771F00668381/$File/EPA-SAB-10-007-unsigned.pdf.
---------------------------------------------------------------------------

    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/m\3\. 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/m\3\, ``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/
m\3\), 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/m\3\). 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.
---------------------------------------------------------------------------

    \27\ 29 CFR 1910.1028, Benzene. Available online at http://www.osha.gov/pls/oshaweb/owadisp.show_document?p_table=STANDARDS&p_id=10042.
    \28\ ACGIH (2001) Benzene. In Documentation of the TLVs[supreg] 
and BEIs[supreg] 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.
    \29\ The 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.''
    \30\ NIOSH. Occupational Safety and Health Guideline for 
Benzene; http://www.cdc.gov/niosh/74-137.html.
---------------------------------------------------------------------------

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., multi-pathway 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,

[[Page 52774]]

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[supreg] 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

[[Page 52775]]

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 dose-response 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.
---------------------------------------------------------------------------

    \31\ Short-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.
---------------------------------------------------------------------------

    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 under-predict 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

[[Page 52776]]

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\
---------------------------------------------------------------------------

    \32\ U.S. EPA. National-Scale Air Toxics Assessment for 1996. 
(EPA 453/R-01-003; January 2001; page 85.)
---------------------------------------------------------------------------

    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 co-occurrence of peak emissions and worst-case 
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 dose-response 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 health-protection, 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).
---------------------------------------------------------------------------

    \33\ IRIS glossary (http://www.epa.gov/NCEA/iris/help_gloss.htm).
    \34\ An 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.
---------------------------------------------------------------------------

    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

[[Page 52777]]

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 effect-specific 
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).
---------------------------------------------------------------------------

    \35\ According 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.
---------------------------------------------------------------------------

    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 short-term 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 site-specific 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 facility-wide 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 
facility-wide 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
--------------------------------------------------------------------------------------------------------------------------------------------------------
                     Maximum individual cancer risk (in 1                                         Maximum chronic noncancer TOSHI \4\
                                 million) \2\                  Estimated      Estimated  annual -------------------------------------- Maximum  off-site
     Number of     ---------------------------------------   population at    cancer  incidence                                         acute  noncancer
  facilities \1\     Actual emissions       Allowable        risk >= 1-in-1    (cases per year)   Actual emissions      Allowable            HQ \5\
                           level         emissions level        million                                level         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.
\2\ Estimated maximum individual excess lifetime cancer risk.
\3\ The 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.
\5\ The maximum estimated acute exposure concentration was divided by available short-term dose-response values to develop an array of HQ values.

[[Page 52778]]

    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 MACT-allowable 
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           100
     (in 1 million)........................................
    Number of facilities with estimated facility-wide                  1
     individual cancer risk of 100-in-1 million or more....
    Number of facilities at which the Oil and Natural Gas              0
     Production source category contributes 50 percent or
     more to the facility-wide individual cancer risks of
     100-in-1 million or more..............................
    Number of facilities with facility-wide individual               140
     cancer risk of 1-in-1 million or more.................
    Number of facilities at which the Oil and Natural Gas             85
     Production source category contributes 50 percent or
     more to the facility-wide individual cancer risk of 1-
     in-1 million or more..................................
Chronic Noncancer Risk:
    Maximum facility-wide chronic noncancer TOSHI..........            9
    Number of facilities with facility-wide maximum                   10
     noncancer TOSHI greater than 1........................
    Number of facilities at which the Oil and Natural Gas              0
     Production source category contributes 50 percent or
     more to the facility-wide maximum noncancer TOSHI of 1
     or more...............................................
------------------------------------------------------------------------

    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 facility-wide 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.
---------------------------------------------------------------------------

    \36\ We 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.
---------------------------------------------------------------------------

    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
----------------------------------------------------------------------------------------------------------------
                                                                              Population with cancer risk at or
                                                                                 above 1-in-1 million due to
                                                             Nationwide    -------------------------------------
                                                                             Source category   Facility-wide HAP
                                                                              HAP emissions        emissions
----------------------------------------------------------------------------------------------------------------
Total Population.......................................        285,000,000            160,000            597,000

[[Page 52779]]

 
                                                 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-in-1 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 MACT-allowable 
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 worst-case 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.

[[Page 52780]]

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 MACT-
allowable emissions, which greatly exceeds the ``presumptive limit on 
maximum individual lifetime risk of approximately 1-in-10 thousand 
[100-in-1 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-the-MACT-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 facility-wide 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.

[[Page 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
--------------------------------------------------------------------------------------------------------------------------------------------------------
                     Maximum individual cancer risk (in 1                                         Maximum chronic noncancer TOSHI \4\
                                 million) \2\                  Estimated      Estimated  annual -------------------------------------- Maximum  off-site
     Number of     ---------------------------------------   population at    cancer  incidence                                         acute  noncancer
  Facilities \1\     Actual  emissions      Allowable        risk >= 1-in-1    (cases per year)  Actual  emissions      Allowable            HQ \5\
                           level         emissions level        million                                level         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.
\2\ Estimated maximum individual excess lifetime cancer risk.
\3\ The EPA IRIS assessment for benzene provides a range of equally-plausible URE (2.2E-06 to 7.8E-06 per ug/m\3\), 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.
\5\ The 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 MACT-allowable 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
 
 
    Number of facilities with estimated facility-wide                  3
     individual cancer risk of 100-in-1 million or more....
    Number of facilities at which the Natural Gas                      1
     Transmission and Storage source category contributes
     50 percent or more to the facility-wide individual
     cancer risks of 100-in-1 million or more..............
    Number of facilities with facility-wide individual                74
     cancer risk of 1-in-1 million or more.................
    Number of facilities at which the Natural Gas                     10
     Transmission and Storage source category contributes
     50 percent or more to the facility-wide individual
     cancer risk of 1-in-1 million or more.................
Chronic Noncancer Risk:
    Maximum facility-wide chronic noncancer TOSHI..........           80
    Number of facilities with facility-wide maximum                   30
     noncancer TOSHI greater than 1........................
    Number of facilities at which the Natural Gas                      0
     Transmission and Storage source category contributes
     50 percent or more to the facility-wide maximum
     noncancer TOSHI of 1 or more..........................
------------------------------------------------------------------------
\1\ We 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 facility-wide MIR 
is 200-in-1 million at two of these facilities, driven by formaldehyde

[[Page 52782]]

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-in-1 million or more are primarily driven by 
formaldehyde emissions from RICE, which will be assessed in a future 
RTR for that category.
---------------------------------------------------------------------------

    \37\ We 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.
---------------------------------------------------------------------------

    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 facility-wide 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
----------------------------------------------------------------------------------------------------------------
                                                                              Population with cancer risk at or
                                                                              above 1-in-1 million due to . . .
                                                             Nationwide    -------------------------------------
                                                                             Source category   Facility-wide HAP
                                                                              HAP emissions        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-in-1 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

[[Page 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 facility-wide 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-in-1 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 facility-wide 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.

[[Page 52784]]

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-by-source 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

[[Page 52785]]

light of the above, we do not believe that the additional costs of 
these programs are justified.
---------------------------------------------------------------------------

    \38\ As 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.
---------------------------------------------------------------------------

    In addition to the plant-wide evaluations, a component analysis was 
also evaluated at gas processing plants for the 40 CFR part 60, subpart 
VVa-level 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.
---------------------------------------------------------------------------

    \39\ Because 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.
---------------------------------------------------------------------------

    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 on-site 
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

[[Page 52786]]

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[deg] 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 non-condenser controls.
---------------------------------------------------------------------------

    \40\ The 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.
---------------------------------------------------------------------------

    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.

[[Page 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-by-case 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).

[[Page 52788]]

    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 production-
specific 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

[[Page 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 
energy-related 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

[[Page 52790]]

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

[[Page 52791]]

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 energy-related 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\
---------------------------------------------------------------------------

    \41\ U.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.
    \42\ U.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.
    \43\ U.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.
    \44\ U.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:[sol][sol]cfpub.epa.gov/ncea/CFM/recordisplay.cfm?deid=149923.
---------------------------------------------------------------------------

    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

[[Page 52792]]

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.
---------------------------------------------------------------------------

    \45\ U.S. EPA (2011), 2011 U.S. Greenhouse Gas Inventory Report 
Executive Summary available on the internet at 
http:[sol][sol]www.epa.gov/climateexchange/emissions/downloads11/US-
GHG-Inventory-2011-Executive Summary.pdf.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \46\ U.S. EPA. Greenhouse Gas Equivalency Calculator available 
at: http://www.epa.gov/cleanenergy/energy-resources/calculator.html 
accessed 07/19/11.
---------------------------------------------------------------------------

    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 interagency-accepted 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.
---------------------------------------------------------------------------

    \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/scc-tsd.pdf; Accessed March 30, 2011.
    \48\ U.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.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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 co-benefit 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

[[Page 52793]]

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 co-benefits 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.
---------------------------------------------------------------------------

    \50\ Marten 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.
---------------------------------------------------------------------------

    Due to the uncertainties involved with the `GWP approach' estimates 
presented and methane climate co-benefits 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.
---------------------------------------------------------------------------

    \51\ Fann, 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.
---------------------------------------------------------------------------

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, facility-wide 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    Code description of the method used
 for Revised Emissions.              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).

[[Page 52794]]

 
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      Enter revised Emission Release Point
 Type.                               Type here.
REVISED End Date..................  Enter revised End Date here.
REVISED Exit Gas Flow Rate........  Enter revised Exit Gas Flowrate here
                                     (ft\3\/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           Enter revised Facility Registry
 Identifier.                         Identifier here, which is an ID
                                     assigned by the EPA Facility
                                     Registry System.
REVISED HAP Emissions Performance   Enter revised HAP Emissions
 Level Code.                         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[supreg] 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[supreg] 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.

[[Page 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 and
                                            Proposed NSPS           Proposed NESHAP         NESHAP amendments
                                                                       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       4,900 tons of methane    3.4 million tons of
                                       methane                                            methane.
                                     ---------------------------------------------------------------------------
                                                            Health effects of HAP exposure.
                                                      Health effects of PM2.5 and ozone exposure.
                                                                Visibility impairment.
                                                                  Vegetation effects.
                                                                   Climate effects.
----------------------------------------------------------------------------------------------------------------
\1\ All estimates are for the implementation year (2015).
\2\ While 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.
\3\ The 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.
\4\ For 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.
\5\ The 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

[[Page 52796]]

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-for-profit 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.

[[Page 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 co-
emitted 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 low-income 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

[[Page 52798]]

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:

Sec.  60.17  Incorporations by reference.

* * * * *
    (a) * * *
    (7) ASTM D86-78, 82, 90, 93, 95, 96, Distillation of Petroleum 
Products, IBR approved for Sec. Sec.  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 Sec. Sec.  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 Sec. Sec.  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:

Sec.  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:

Sec.  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

[[Page 52799]]

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

Sec.  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.

Sec.  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 Sec.  60.5430), except that a centrifugal 
compressor located at a well site (as defined in Sec.  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 Sec.  60.5430), except that a 
reciprocating compressor located at a well site (as defined in Sec.  
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 Sec.  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 Sec.  
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 Sec.  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 Sec. Sec.  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 Sec.  60.5430) not located at the 
onshore natural gas processing plant site is exempt from the provisions 
of Sec. Sec.  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 Sec.  60.5423(c) but are not 
required to comply with Sec. Sec.  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 Sec. Sec.  60.5405 
through 60.5407, and Sec. Sec.  60.5410(g), 60.5415(g), and Sec.  
60.5423 of this subpart.

Sec.  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.

Sec.  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.

[[Page 52800]]

    (a) Except as provided in paragraph (f) of this section, for each 
well completion operation with hydraulic fracturing, as defined in 
Sec.  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 Sec.  
60.5420(c)(1)(iii).
    (c) You must demonstrate initial compliance with the standards that 
apply to gas wellhead affected facilities as required by Sec.  60.5410.
    (d) You must demonstrate continuous compliance with the standards 
that apply to gas wellhead affected facilities as required by Sec.  
60.5415.
    (e) You must perform the required notification, recordkeeping, and 
reporting as required by Sec.  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 
Sec.  60.5420(c)(1)(iii) for wildcat or delineation wells.

Sec.  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 
Sec.  60.5410.
    (c) You must demonstrate continuous compliance with the standards 
that apply to centrifugal compressor affected facilities as required by 
Sec.  60.5415.
    (d) You must perform the required notification, recordkeeping, and 
reporting as required by Sec.  60.5420.

Sec.  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 
Sec.  60.5410.
    (c) You must demonstrate continuous compliance with standards that 
apply to reciprocating compressor affected facilities as required by 
Sec.  60.5415.
    (d) You must perform the required notification, recordkeeping, and 
reporting as required by Sec.  60.5420.

Sec.  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 Sec.  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 Sec.  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 Sec.  
60.5410.
    (e) You must demonstrate continuous compliance with standards that 
apply to pneumatic controller affected facilities as required by Sec.  
60.5415.
    (f) You must perform the required notification, recordkeeping, and 
reporting as required by Sec.  60.5420, except that you are not 
required to submit the notifications specified in Sec.  60.5420(a).

Sec.  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 Sec.  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 Sec.  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 Sec.  
60.5410.
    (d) You must demonstrate continuous compliance with standards that 
apply to storage vessel affected facilities as required by Sec.  
60.5415.
    (e) You must perform the required notification, recordkeeping, and 
reporting as required by Sec.  60.5420.

Sec.  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 Sec.  
60.5430), except compressors, within a process unit.
    (a) You must comply with the requirements of Sec.  60.482-1a(a), 
(b), and (d), Sec.  60.482-2a, and Sec.  60.482-4a through 60.482-11a, 
except as provided in Sec.  60.5401.

[[Page 52801]]

    (b) You may elect to comply with the requirements of Sec. Sec.  
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 Sec.  60.5402 
of this subpart.
    (d) You must comply with the provisions of Sec.  60.485a of this 
part except as provided in paragraph (f) of this section.
    (e) You must comply with the provisions of Sec. Sec.  60.486a and 
60.487a of this part except as provided in Sec. Sec.  60.5401, 60.5421, 
and 60.5422 of this part.
    (f) You must use the following provision instead of Sec.  
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 Sec.  60.17) must be used.

Sec.  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 Sec.  60.485a(b) except as 
provided in Sec.  60.5400(c) and in paragraph (b)(4) of this section, 
and Sec.  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 Sec.  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 Sec.  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 
Sec.  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 Sec. Sec.  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 Sec. Sec.  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 Sec.  60.18.
    (g) An owner or operator may use the following provisions instead 
of Sec.  60.485a(e):
    (1) Equipment is in heavy liquid service if the weight percent 
evaporated is 10 percent or less at 150 [deg]C (302 [deg]F) as 
determined by ASTM Method D86-78, 82, 90, 95, or 96 (incorporated by 
reference as specified in Sec.  60.17).
    (2) Equipment is in light liquid service if the weight percent 
evaporated is greater than 10 percent at 150 [deg]C (302 [deg]F) as 
determined by ASTM Method D86-78, 82, 90, 95, or 96 (incorporated by 
reference as specified in Sec.  60.17).

Sec.  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.

Sec.  60.5405  What standards apply to sweetening units at onshore 
natural gas processing plants?

    (a) During the initial performance test required by Sec.  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 Sec.  60.8, you 
must use

[[Page 52802]]

the test methods in Appendix A of this part or other methods and 
procedures as specified in this section, except as provided in 
paragraph Sec.  60.8(b).
    (b) During a performance test required by Sec.  60.8, you must 
determine the minimum required reduction efficiencies (Z) of 
SO2 emissions as required in Sec.  60.5405(a) and (b) as 
follows:
    (1) The average sulfur feed rate (X) must be computed as follows:

X - KQa[gamma]

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/kg-mole) (1000 kg S/Mg))
    = 1.331 x 10-3 Mg/dscm, for metric units
    = (32 lb S/lb-mole) / ((385.36 dscf/lb-mole) (2240 lb S/long 
ton))
= 3.707 x 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 Sec.  60.5408 or a 
chromatographic procedure following ASTM E-260 (incorporated by 
reference--see Sec.  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 x 
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 Sec.  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:
[GRAPHIC] [TIFF OMITTED] TP23AU11.005

    (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:
[GRAPHIC] [TIFF OMITTED] TP23AU11.006

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 m\2\ (54 ft\2\) or at a point no closer to the 
walls than 1 m (39 in) if the cross-sectional area is 5 m\2\ 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 x 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 
ft\3\/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 x 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 
oxidation-type 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 x 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.

Sec.  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 Sec.  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 Sec.  
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

[[Page 52803]]

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 Sec.  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 Sec.  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 Sec.  
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 Sec.  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 
Sec.  60.8 to demonstrate compliance with the standards under Sec.  
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 Sec.  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 Sec.  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 Sec.  
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:
[GRAPHIC] [TIFF OMITTED] TP23AU11.000

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 Sec.  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 Sec.  60.13 of the General 
Provisions. For conducting the continuous emission monitoring system 
performance evaluation required by Sec.  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.

[[Page 52804]]

Sec.  60.5408  What is an optional procedure for measuring hydrogen 
sulfide in acid gas--Tutwiler Procedure? \1\
---------------------------------------------------------------------------

    \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).
---------------------------------------------------------------------------

    (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 glass-
stoppered 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

[[Page 52805]]

[GRAPHIC] [TIFF OMITTED] TP23AU11.001

BILLING CODE 6560-50-C

Sec.  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 Sec.  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 Sec.  
60.5375(b) or (f) for each well completion operation conducted during 
the initial compliance period.

[[Page 52806]]

    (3) You have submitted the initial annual report for your wellhead 
affected facility as required in Sec.  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 
Sec.  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 Sec.  
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 Sec.  
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 Sec.  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 Sec.  63.771(c) of this chapter 
connected to a control device that meets the conditions specified in 
Sec.  63.771(d).
    (2) You have conducted an initial performance test as required in 
Sec.  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 Sec.  63.772(f).
    (3) You have conducted the initial inspections required in Sec.  
63.773(c) of this chapter.
    (4) You have installed and operated continuous parameter monitoring 
systems in accordance with Sec.  63.773(d) of this chapter.
    (5) If you are exempt from the standards of Sec.  60.5395 according 
to Sec.  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 Sec.  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 Sec.  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 Sec.  60.5405(a), during the initial performance test as 
required by Sec.  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 Sec.  
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.

Sec.  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 Sec.  60.5430) specified in Sec.  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 
Sec.  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 Sec.  60.5390(a), (b) or (c).
    (e) For each storage vessel affected facility, continuous 
compliance is demonstrated according to Sec.  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 Sec.  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

[[Page 52807]]

Sec.  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 Sec.  
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 Sec. Sec.  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 Sec.  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 
Sec.  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 Sec. Sec.  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.

Sec.  60.5420  What are my notification, reporting, and recordkeeping 
requirements?

    (a) You must submit the notifications required in Sec.  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 Sec.  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 Sec.  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 Sec.  
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 Sec.  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

[[Page 52808]]

specified in Sec.  60.5375 for each gas well affected facility.
    (iii) Records specified in Sec.  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 Sec.  
60.5395(a)(1), the records specified in Sec.  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 Sec.  60.5395(a)(1) or (a)(2).
    (c) Recordkeeping requirements. You must maintain the records 
identified as specified in Sec.  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 Sec.  60.5375.
    (iii) Records required in Sec.  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 Sec.  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 Sec.  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 Sec.  63.766, 
the records specified in Sec.  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 Sec.  60.5395(a)(1) and (a)(2).

Sec.  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 Sec.  60.486a.
    (b) The following recordkeeping requirements apply to pressure 
relief devices subject to the requirements of Sec.  60.5401(b)(1) of 
this subpart.
    (1) When each leak is detected as specified in Sec.  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 Sec.  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.

[[Page 52809]]

    (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 Sec.  
60.482-4a(a). The designation of equipment subject to the provisions of 
Sec.  60.482-4a(a) must be signed by the owner or operator.

Sec.  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 Sec.  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 Sec.  60.487a(b)(1) through (4): Number of pressure relief devices 
subject to the requirements of Sec.  60.5401(b) except for those 
pressure relief devices designated for no detectable emissions under 
the provisions of Sec.  60.482-4a(a) and those pressure relief devices 
complying with Sec.  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 Sec.  
60.487a(c)(2)(i) through (vi):
    (1) Number of pressure relief devices for which leaks were detected 
as required in Sec.  60.5401(b)(2); and
    (2) Number of pressure relief devices for which leaks were not 
repaired as required in Sec.  60.5401(b)(3).

Sec.  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 Sec.  60.5405(a) and (b) and Sec.  60.5407(a) through (g) 
for at least 2 years following the date of the measurements. This 
requirement is included under Sec.  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 Sec.  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 Sec.  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 Sec.  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.

Sec.  60.5425  What part of the General Provisions apply to me?

    Table 3 to this subpart shows which parts of the General Provisions 
in Sec. Sec.  60.1 through 60.19 apply to you.

Sec.  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 Sec.  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

[[Page 52810]]

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 Sec.  60.485a(e) or 
Sec.  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, non-corrosive 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

[[Page 52811]]

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)
----------------------------------------------------------------------------------------------------------------
                                                            Sulfur feed rate (X), LT/D
 H2S content of acid gas (Y), %  -------------------------------------------------------------------------------
                                   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         97.9
                                                                     smaller
----------------------------------------------------------------------------------------------------------------
10 <= Y < 20....................             79.0   88.5X0.0101Y0.0125.          93.5                93.5
                                                    or 97.9, whichever
                                                     is smaller.
----------------------------------------------------------------------------------------------------------------
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)
----------------------------------------------------------------------------------------------------------------
                                                            Sulfur feed rate (X), LT/D
 H2S content of acid gas (Y), %  -------------------------------------------------------------------------------
                                   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          97.5
                                                                    is smaller
----------------------------------------------------------------------------------------------------------------
10 <= Y < 20....................             74.0   85.35X0.0144Y0.0128          90.8                90.8
                                                    or 90.8, whichever
                                                     is smaller.
----------------------------------------------------------------------------------------------------------------
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 Sec.   60.5425, you must comply with the following applicable General Provisions]
----------------------------------------------------------------------------------------------------------------
   General provisions  citation         Subject of citation      Applies to subpart?          Explanation
----------------------------------------------------------------------------------------------------------------
Sec.   60.1.......................  General applicability of    Yes.
                                     the General Provisions.
Sec.   60.2.......................  Definitions...............  Yes..................  Additional terms defined
                                                                                        in Sec.   60.5430.
Sec.   60.3.......................  Units and abbreviations...  Yes.
Sec.   60.4.......................  Address...................  Yes.
Sec.   60.5.......................  Determination of            Yes.
                                     construction or
                                     modification.
Sec.   60.6.......................  Review of plans...........  Yes.
Sec.   60.7.......................  Notification and record     Yes..................  Except that Sec.   60.7
                                     keeping.                                           only applies as
                                                                                        specified in Sec.
                                                                                        60.5420(a).

[[Page 52812]]

 
Sec.   60.8.......................  Performance tests.........  No...................  Performance testing is
                                                                                        required for storage
                                                                                        vessels as specified in
                                                                                        40 CFR part 63, subpart
                                                                                        HH.
Sec.   60.9.......................  Availability of             Yes.
                                     information.
Sec.   60.10......................  State authority...........  Yes.
Sec.   60.11......................  Compliance with standards   No...................  Requirements are
                                     and maintenance                                    specified in subpart
                                     requirements.                                      OOOO.
Sec.   60.12......................  Circumvention.............  Yes.
Sec.   60.13......................  Monitoring requirements...  Yes..................  Continuous monitors are
                                                                                        required for storage
                                                                                        vessels.
Sec.   60.14......................  Modification..............  Yes.
Sec.   60.15......................  Reconstruction............  Yes.
Sec.   60.16......................  Priority list.............  Yes.
Sec.   60.17......................  Incorporations by           Yes.
                                     reference.
Sec.   60.18......................  General control device      Yes.
                                     requirements.
Sec.   60.19......................  General notification and    Yes.
                                     reporting requirement.
----------------------------------------------------------------------------------------------------------------

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:

Sec.  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 Sec. Sec.  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 Sec. Sec.  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 Sec. Sec.  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 Sec. Sec.  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 
Sec. Sec.  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:

Sec.  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 Sec.  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 Sec.  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 Sec.  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.
* * * * *

[[Page 52813]]

    (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 Sec.  
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 Sec.  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 Sec.  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 Sec.  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 Sec.  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 Sec.  63.6(i).
    (10) Each large glycol dehydration unit, as defined in Sec.  
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 Sec.  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:

Sec.  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 long-term 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

[[Page 52814]]

Mg/yr, determined according to Sec.  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 Sec.  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 [deg]C, or  
2.5 [deg]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:

Sec.  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:

Sec.  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 Sec.  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

[[Page 52815]]

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:

Sec.  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 Sec.  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 Sec.  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 Sec.  63.771(c). The control 
device(s) shall be designed and operated in accordance with the 
requirements of Sec.  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 Sec.  
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 Sec.  
63.771(c). The control device(s) shall be designed and operated in 
accordance with the requirements of Sec.  63.771(d), except that the 
performance levels specified in Sec.  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 Sec.  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.
[GRAPHIC] [TIFF OMITTED] TP23AU11.002

Where:

ELBTEX = Unit-specific BTEX emission limit, megagrams per 
year;
1.10 x 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 
Sec.  63.771(c). The control device(s) shall be designed and operated 
in accordance with the requirements of Sec.  63.771(f).
    (B) Meet the emissions limit through process modifications in 
accordance with the requirements specified in Sec.  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 
Sec.  63.771(e) and emissions in accordance with the requirements 
specified in Sec.  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 Sec.  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:

Sec.  63.766  Storage vessel standards.

    (a) This section applies to each storage vessel (as defined in 
Sec.  63.761) subject to this subpart.
    (b) The owner or operator of a storage vessel (as defined in Sec.  
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 Sec.  63.771(c), to a control device or a 
combination of control devices that meets any of the conditions 
specified in Sec.  63.771(d). The cover shall be designed and operated 
in accordance with the requirements of Sec.  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

[[Page 52816]]

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:

Sec.  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, Sec. Sec.  61.241 through 61.247, except as specified in 
paragraphs (c)(1) through (8) of this section, except for valves 
subject to Sec.  61.247-2(b) a leak is detected if an instrument 
reading of 500 ppm or greater is measured.
* * * * *
    (8) Flares, as defined in Sec.  63.761, used to comply with this 
subpart shall comply with the requirements of Sec.  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:

Sec.  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 Sec.  
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 Sec.  63.772(e).
    (iii) A flare, as defined in Sec.  63.761, that is designed and 
operated in accordance with the requirements of Sec.  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 Sec.  63.765, Sec.  63.766, and Sec.  
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 Sec.  63.774(b)(7)(ix). The schedule 
for replacement shall be submitted with the Notification of Compliance 
Status Report as specified in Sec.  63.775(d)(5)(iv). Each carbon 
replacement must be reported in the Periodic Reports as specified in 
Sec.  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 Sec.  
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 Sec.  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 Sec.  
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 Sec.  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 Sec.  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

[[Page 52817]]

determined in accordance with the requirements of Sec.  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 Sec.  
63.772(e); or
    (iii) A flare, as defined in Sec.  63.761, that is designed and 
operated in accordance with the requirements of Sec.  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 Sec.  63.773(d), the owner or operator shall 
demonstrate compliance according to the requirements of either Sec.  
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:

Sec.  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-GLYCalc\TM\, Version 3.0 or higher, 
and the procedures presented in the associated GRI-GLYCalc\TM\ 
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 Sec.  63.772(a)(1)(i) or (ii), or an 
alternative method according to Sec.  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 Sec.  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 Sec.  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 Sec.  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-GLYCalc\TM\, Version 3.0 or higher, 
and the procedures presented in the associated GRI-GLYCalc\TM\ 
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-GLYCalc\TM\, 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 Sec.  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

[[Page 52818]]

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 Sec.  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 Sec.  63.761, that is designed and operated in 
accordance with Sec.  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 Sec.  63.761, in accordance with the requirements specified 
in Sec.  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 Sec.  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 Sec.  63.765(b)(1)(iii), or 
the BTEX emission limit specified in Sec.  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 Sec.  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 Sec.  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:
    [GRAPHIC] [TIFF OMITTED] TP23AU11.003
    
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 x 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 Sec.  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 
Sec.  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 Sec.  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 Sec.  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 Sec.  
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, Sec.  63.772(h), or
    (2) A combustion control device tested under Sec.  63.772(e) that 
meets the outlet TOC or HAP performance level specified in Sec.  
63.771(d)(1)(i)(B) and that

[[Page 52819]]

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 Sec.  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 Sec.  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-GLYCalc\TM\, 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 Sec.  
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 Sec.  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 Sec.  63.775(e), 
following the change.
* * * * *
    (2) The owner or operator shall calculate the daily average of the 
applicable monitored parameter in accordance with Sec.  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 Sec.  
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 Sec.  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 Sec.  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 Sec.  63.773(d)(5)(ii). For sources 
required to meet the BTEX limit in accordance with Sec.  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 Sec.  
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 
Sec.  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 Sec.  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 Sec.  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

[[Page 52820]]

compliance dates specified in Sec.  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 Sec.  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 
Sec.  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 Sec.  
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 
Silonite-coated 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

[[Page 52821]]

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 Sec.  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 Sec.  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 Sec.  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 Sec.  
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 Sec.  
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

[[Page 52822]]

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:

Sec.  63.773  Inspection and monitoring requirements.

* * * * *
    (b) The owner or operator of a control device whose model was 
tested under Sec.  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 Sec.  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 Sec.  
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 Sec.  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 Sec.  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 Sec.  63.8(c)(1) and (c)(3); and
    (E) Ongoing reporting and recordkeeping procedures in accordance 
with provisions in Sec.  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 site-specific 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 Sec.  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

[[Page 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 Sec.  
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 Sec.  
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 Sec.  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 Sec.  63.772(e)(3) to demonstrate 
that the control device achieves the applicable performance 
requirements specified in Sec.  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 Sec.  63.772(e)(4) to demonstrate 
that the control device achieves the applicable performance 
requirements specified in Sec.  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 Sec.  63.772(h) to 
demonstrate that the control device achieves the applicable performance 
requirements specified in Sec.  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 Sec.  63.772(e)(3) to demonstrate 
that the condenser achieves the applicable performance requirements in 
Sec.  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 Sec.  63.772(e)(4)(i) to 
demonstrate that the condenser achieves the applicable performance 
requirements specified in Sec.  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-GLYCalc\TM\, Version 3.0 or higher, to generate a condenser 
performance curve.
* * * * *
    (6) * * *
    (ii) For sources meeting Sec.  63.771(d)(1)(ii), an excursion 
occurs when the 365-day average condenser efficiency calculated 
according to the requirements specified in Sec.  63.772(g)(2)(iii) is 
less than 95.0 percent. For sources meeting Sec.  63.771(f)(1), an 
excursion occurs when the 365-day average condenser efficiency 
calculated according to the requirements specified in Sec.  
63.772(g)(2)(iii) is less than 95.0 percent of the identified 365-day 
required percent reduction.
    (iii) For sources meeting Sec.  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 Sec.  63.772(g)(2)(iii)(A) or (B) is less than 90.0 
percent. For sources meeting Sec.  63.771(d)(1)(ii), an excursion 
occurs when the 365-day average condenser efficiency calculated 
according to the requirements specified in Sec.  63.772(g)(2)(iii) is 
less than the identified 365-day required percent reduction.
* * * * *
    (vi) For control device whose model is tested under Sec.  63.772(h) 
an excursion occurs when:
    (A) The inlet gas flow rate exceeds the maximum established during 
the test conducted under Sec.  63.772(h).
    (B) Failure of the monthly visible emissions test conducted under 
Sec.  63.772(i)(3) occurs.
* * * * *
    (8) * * *
    (i) * * *
    (A) During a malfunction when the affected facility is operated 
during such

[[Page 52824]]

period in accordance with Sec.  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 Sec.  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:

Sec.  63.774  Recordkeeping requirements.

* * * * *
    (b) * * *
    (3) Records specified in Sec.  63.10(c) for each monitoring system 
operated by the owner or operator in accordance with the requirements 
of Sec.  63.773(d). Notwithstanding the requirements of Sec.  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 Sec.  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 Sec.  63.772(h), 
the records required in paragraph (h) of this section.
* * * * *
    (7) * * *
    (ix) Records identifying the carbon replacement schedule under 
Sec.  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 Sec.  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 Sec.  63.772(h) to comply with Sec.  63.771(d), (e)(3)(ii) 
and (f)(1):
    (1) All visible emission readings and flowrate measurements made 
during the compliance determination required by Sec.  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 
Sec.  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:

Sec.  63.775  Reporting requirements.

* * * * *
    (b) * * *
    (1) The initial notifications required for existing affected 
sources under Sec.  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 Sec.  63.760(f)(7) or (9) 
shall submit an initial notification required for existing affected 
sources under Sec.  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 Sec.  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 Sec.  63.764(j), including actions taken 
to correct a malfunction.
    (7) [Reserved]
* * * * *
    (c) * * *
    (1) The initial notifications required under Sec.  63.9(b)(2) not 
later than January 3, 2008. In addition to submitting your initial 
notification to the addressees specified under Sec.  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

[[Page 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 Sec.  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 Sec.  
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 Sec.  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 Sec.  
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 Sec.  
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 Sec.  63.771(d)(1), (e)(3)(ii) or (f)(1).
* * * * *
    (iv) For each carbon adsorber, the predetermined carbon replacement 
schedule as required in Sec.  63.771(d)(5)(i).
* * * * *
    (11) The owner or operator shall submit the analysis prepared under 
Sec.  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 Sec.  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 Sec.  63.772(h), the data listed 
under Sec.  63.772(h)(8).
    (14) For each combustion control device model tested under Sec.  
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 Sec.  
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 Sec.  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 Sec.  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 Sec.  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 Sec.  
63.772(e)(3) conducted during the reporting period.
    (xii) For each carbon adsorber used to meet the control device 
requirements of Sec.  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 Sec.  63.773(b) the records specified in Sec.  
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 
Sec.  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 Sec.  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

* * * * *

[[Page 52826]]

       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
----------------------------------------------------------------------------------------------------------------
Sec.   63.1(a)(1)...................  Yes.
Sec.   63.1(a)(2)...................  Yes.
Sec.   63.1(a)(3)...................  Yes.
Sec.   63.1(a)(4)...................  Yes.
Sec.   63.1(a)(5)...................  No.......................  Section reserved.
Sec.   63.1(a)(6)...................  Yes.
Sec.   63.1(a)(7) through (a)(9)....  No.......................  Section reserved.
Sec.   63.1(a)(10)..................  Yes.
Sec.   63.1(a)(11)..................  Yes.
Sec.   63.1(a)(12)..................  Yes.
Sec.   63.1(b)(1)...................  No.......................  Subpart HH specifies applicability.
Sec.   63.1(b)(2)...................  No.......................  Section reserved.
Sec.   63.1(b)(3)...................  Yes.
Sec.   63.1(c)(1)...................  No.......................  Subpart HH specifies applicability.
Sec.   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 Sec.
                                                                    63.760(h).
Sec.   63.1(c)(3) and (c)(4)........  No.......................  Section reserved.
Sec.   63.1(c)(5)...................  Yes.
Sec.   63.1(d)......................  No.......................  Section reserved.
Sec.   63.1(e)......................  Yes.
Sec.   63.2.........................  Yes......................  Except definition of major source is unique for
                                                                  this source category and there are additional
                                                                  definitions in subpart HH.
Sec.   63.3(a) through (c)..........  Yes.
Sec.   63.4(a)(1) through (a)(2)....  Yes.
Sec.   63.4(a)(3) through (a)(5)....  No.......................  Section reserved.
Sec.   63.4(b)......................  Yes.
Sec.   63.4(c)......................  Yes.
Sec.   63.5(a)(1)...................  Yes.
Sec.   63.5(a)(2)...................  Yes.
Sec.   63.5(b)(1)...................  Yes.
Sec.   63.5(b)(2)...................  No.......................  Section reserved.
Sec.   63.5(b)(3)...................  Yes.
Sec.   63.5(b)(4)...................  Yes.
Sec.   63.5(b)(5)...................  No.......................  Section reserved.
Sec.   63.5(b)(6)...................  Yes.
Sec.   63.5(c)......................  No.......................  Section reserved.
Sec.   63.5(d)(1)...................  Yes.
Sec.   63.5(d)(2)...................  Yes.
Sec.   63.5(d)(3)...................  Yes.
Sec.   63.5(d)(4)...................  Yes.
Sec.   63.5(e)......................  Yes.
Sec.   63.5(f)(1)...................  Yes.
Sec.   63.5(f)(2)...................  Yes.
Sec.   63.6(a)......................  Yes.
Sec.   63.6(b)(1)...................  Yes.
Sec.   63.6(b)(2)...................  Yes.
Sec.   63.6(b)(3)...................  Yes.
Sec.   63.6(b)(4)...................  Yes.
Sec.   63.6(b)(5)...................  Yes.
Sec.   63.6(b)(6)...................  No.......................  Section reserved.
Sec.   63.6(b)(7)...................  Yes.
Sec.   63.6(c)(1)...................  Yes.
Sec.   63.6(c)(2)...................  Yes.
Sec.   63.6(c)(3) through (c)(4)....  No.......................  Section reserved.
Sec.   63.6(c)(5)...................  Yes.
Sec.   63.6(d)......................  No.......................  Section reserved.
Sec.   63.6(e)......................  Yes.
Sec.   63.6(e)(1)(i)................  No.......................  See Sec.   63.764(j) for general duty
                                                                  requirement.
Sec.   63.6(e)(1)(ii)...............  No.
Sec.   63.6(e)(1)(iii)..............  Yes.
Sec.   63.6(e)(2)...................  No.......................  Section reserved.
Sec.   63.6(e)(3)...................  No.
Sec.   63.6(f)(1)...................  No.
Sec.   63.6(f)(2)...................  Yes.
Sec.   63.6(f)(3)...................  Yes.
Sec.   63.6(g)......................  Yes.
Sec.   63.6(h)......................  No.......................  Subpart HH does not contain opacity or visible
                                                                  emission standards.
Sec.   63.6(i)(1) through (i)(14)...  Yes.
Sec.   63.6(i)(15)..................  No.......................  Section reserved.
Sec.   63.6(i)(16)..................  Yes.
Sec.   63.6(j)......................  Yes.

[[Page 52827]]

 
Sec.   63.7(a)(1)...................  Yes.
Sec.   63.7(a)(2)...................  Yes......................  But the performance test results must be
                                                                  submitted within 180 days after the compliance
                                                                  date.
Sec.   63.7(a)(3)...................  Yes.
Sec.   63.7(b)......................  Yes.
Sec.   63.7(c)......................  Yes.
Sec.   63.7(d)......................  Yes.
Sec.   63.7(e)(1)...................  No.
Sec.   63.7(e)(2)...................  Yes.
Sec.   63.7(e)(3)...................  Yes.
Sec.   63.7(e)(4)...................  Yes.
Sec.   63.7(f)......................  Yes.
Sec.   63.7(g)......................  Yes.
Sec.   63.7(h)......................  Yes.
Sec.   63.8(a)(1)...................  Yes.
Sec.   63.8(a)(2)...................  Yes.
Sec.   63.8(a)(3)...................  No.......................  Section reserved.
Sec.   63.8(a)(4)...................  Yes.
Sec.   63.8(b)(1)...................  Yes.
Sec.   63.8(b)(2)...................  Yes.
Sec.   63.8(b)(3)...................  Yes.
Sec.   63.8(c)(1)...................  No.
Sec.   63.8(c)(1)(i)................  No.......................
Sec.   63.8(c)(1)(ii)...............  Yes.
Sec.   63.8(c)(1)(iii)..............  Pending.
Sec.   63.8(c)(2)...................  Yes.
Sec.   63.8(c)(3)...................  Yes.
Sec.   63.8(c)(4)...................  Yes.
Sec.   63.8(c)(4)(i)................  No.......................  Subpart HH does not require continuous opacity
                                                                  monitors.
Sec.   63.8(c)(4)(ii)...............  Yes.
Sec.   63.8(c)(5) through (c)(8)....  Yes.
Sec.   63.8(d)......................  Yes.
Sec.   63.8(d)(3)...................  Yes......................  Except for last sentence, which refers to an
                                                                  SSM plan. SSM plans are not required.
Sec.   63.8(e)......................  Yes......................  Subpart HH does not specifically require
                                                                  continuous emissions monitor performance
                                                                  evaluation, however, the Administrator can
                                                                  request that one be conducted.
Sec.   63.8(f)(1) through (f)(5)....  Yes.
Sec.   63.8(f)(6)...................  Yes.
Sec.   63.8(g)......................  No.......................  Subpart HH specifies continuous monitoring
                                                                  system data reduction requirements.
Sec.   63.9(a)......................  Yes.
Sec.   63.9(b)(1)...................  Yes.
Sec.   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 Sec.   63.764(e) do
                                                                  not have to submit initial notifications.
Sec.   63.9(b)(3)...................  No.......................  Section reserved.
Sec.   63.9(b)(4)...................  Yes.
Sec.   63.9(b)(5)...................  Yes.
Sec.   63.9(c)......................  Yes.
Sec.   63.9(d)......................  Yes.
Sec.   63.9(e)......................  Yes.
Sec.   63.9(f)......................  No.......................  Subpart HH does not have opacity or visible
                                                                  emission standards.
Sec.   63.9(g)(1)...................  Yes.
Sec.   63.9(g)(2)...................  No.......................  Subpart HH does not have opacity or visible
                                                                  emission standards.
Sec.   63.9(g)(3)...................  Yes.
Sec.   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.
Sec.   63.9(h)(4)...................  No.......................  Section reserved.
Sec.   63.9(h)(5) through (h)(6)....  Yes.
Sec.   63.9(i)......................  Yes.
Sec.   63.9(j)......................  Yes.
Sec.   63.10(a).....................  Yes.
Sec.   63.10(b)(1)..................  Yes......................  Sec.   63.774(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.
Sec.   63.10(b)(2)..................  Yes.
Sec.   63.10(b)(2)(i)...............  No.......................
Sec.   63.10(b)(2)(ii)..............  No.......................  See Sec.   63.774(g) for recordkeeping of
                                                                  occurrence, duration, and actions taken during
                                                                  malfunctions.
Sec.   63.10(b)(2)(iii).............  Yes.
Sec.   63.10(b)(2)(iv) through        No.
 (b)(2)(v).
Sec.   63.10(b)(2)(vi) through        Yes.
 (b)(2)(xiv).

[[Page 52828]]

 
Sec.   63.10(b)(3)..................  Yes......................  Sec.   63.774(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.
Sec.   63.10(c)(1)..................  Yes.
Sec.   63.10(c)(2) through (c)(4)...  No.......................  Sections reserved.
Sec.   63.10(c)(5) through (8)(c)(8)  Yes.
Sec.   63.10(c)(9)..................  No.......................  Section reserved.
Sec.   63.10(c)(10) through (11)....  No.......................  See Sec.   63.774(g) for recordkeeping of
                                                                  malfunctions.
Sec.   63.10(c)(12) through (14)....  Yes.
Sec.   63.10(c)(15).................  No.
Sec.   63.10(d)(1)..................  Yes.
Sec.   63.10(d)(2)..................  Yes......................  Area sources located outside UA plus offset and
                                                                  UC boundaries do not have to submit
                                                                  performance test reports.
Sec.   63.10(d)(3)..................  Yes.
Sec.   63.10(d)(4)..................  Yes.
Sec.   63.10(d)(5)..................  No.......................  See Sec.   63.775(b)(6) or (c)(6) for reporting
                                                                  of malfunctions.
Sec.   63.10(e)(1)..................  Yes......................  Area sources located outside UA plus offset and
                                                                  UC boundaries are not required to submit
                                                                  reports.
Sec.   63.10(e)(2)..................  Yes......................  Area sources located outside UA plus offset and
                                                                  UC boundaries are not required to submit
                                                                  reports.
Sec.   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.
Sec.   63.10(e)(3)(i)(A)............  Yes.
Sec.   63.10(e)(3)(i)(B)............  Yes.
Sec.   63.10(e)(3)(i)(C)............  No.......................  Section reserved.
Sec.   63.10(e)(3)(ii) through        Yes.
 (viii).
Sec.   63.10(f).....................  Yes.
Sec.   63.11(a) and (b).............  Yes.
Sec.   63.11(c), (d), and (e).......  Yes.
Sec.   63.12(a) through (c).........  Yes.
Sec.   63.13(a) through (c).........  Yes.
Sec.   63.14(a) and (b).............  Yes.
Sec.   63.15(a) and (b).............  Yes.
Sec.   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:

Sec.  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 Sec.  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 Sec.  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 Sec.  
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,

[[Page 52829]]

1998, shall achieve compliance with the provisions of this subpart no 
later than June 17, 2002 except as provided for in Sec.  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 
Sec.  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 Sec.  63.6(i).
    (4) Each affected small glycol dehydration unit, as defined in 
Sec.  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 Sec.  
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 Sec.  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:

Sec.  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 long-term 
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 Sec.  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 Sec.  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 [deg]C, or  
2.5 [deg]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:

Sec.  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 Sec.  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

[[Page 52830]]

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:

Sec.  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:

Sec.  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 Sec.  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 Sec.  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 Sec.  63.1281(c). The control 
device(s) shall be designed and operated in accordance with the 
requirements of Sec.  63.1281(d).
    (ii) [Reserved]
    (iii) You must limit BTEX emissions from each small glycol 
dehydration unit, as defined in Sec.  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.
[GRAPHIC] [TIFF OMITTED] TP23AU11.007

[[Page 52831]]

Where:

ELBTEX = Unit-specific BTEX emission limit, megagrams per 
year;
6.42 x 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 
Sec.  63.1281(c). The control device(s) shall be designed and operated 
in accordance with the requirements of Sec.  63.1281(f).
    (B) Meet the emissions limit through process modifications in 
accordance with the requirements specified in Sec.  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 
Sec.  63.1281(e) and emissions in accordance with the requirements 
specified in Sec.  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 Sec.  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:

Sec.  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 Sec.  
63.1282(d), operates at a minimum temperature of 760 [deg]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 Sec.  63.1282(d).
    (iii) A flare, as defined in Sec.  63.1271, that is designed and 
operated in accordance with the requirements of Sec.  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 Sec.  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 Sec.  63.1284(b)(7)(ix). The 
schedule for replacement shall be submitted with the Notification of 
Compliance Status Report as specified in Sec.  63.1285(d)(4)(iv). Each 
carbon replacement must be reported in the Periodic Reports as 
specified in Sec.  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 Sec.  
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 Sec.  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

[[Page 52832]]

determined in Sec.  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 Sec.  
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 Sec.  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 Sec.  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 Sec.  
63.1282(d); or
    (iii) A flare, as defined in Sec.  63.1271, that is designed and 
operated in accordance with the requirements of Sec.  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 Sec.  63.1283(d), the owner or operator shall 
demonstrate compliance according to the requirements of either Sec.  
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:

Sec.  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-GLYCalc\TM\, Version 3.0 or higher, 
and the procedures presented in the associated GRI-GLYCalc\TM\ 
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 Sec.  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 Sec.  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 Sec.  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

[[Page 52833]]

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-GLYCalc\TM\, Version 3.0 or higher, 
and the procedures presented in the associated GRI-GLYCalc\TM\ 
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-GLYCalc\TM\, 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 Sec.  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 Sec.  
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 Sec.  63.1271, that is designed and operated in 
accordance with Sec.  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 Sec.  63.1271, in accordance with the requirements specified 
in Sec.  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 Sec.  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 Sec.  63.1281(d)(1)(i)(B), 
or the BTEX emission limit specified in Sec.  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 Sec.  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 Sec.  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:
    [GRAPHIC] [TIFF OMITTED] TP23AU11.004
    
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 x 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 Sec.  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 
Sec.  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

[[Page 52834]]

control device at an existing major source chooses to replace such 
device with a control device whose model is tested under Sec.  
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 Sec.  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 Sec.  
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, Sec.  63.1282(g), or
    (2) A combustion control device tested under Sec.  63.1282(d) that 
meets the outlet TOC or HAP performance level specified in Sec.  
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 Sec.  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 Sec.  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-GLYCalc\TM\, 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 Sec.  
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 Sec.  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 Sec.  63.1285(e), 
following the change.
* * * * *
    (2) The owner or operator shall calculate the daily average of the 
applicable monitored parameter in accordance with Sec.  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 Sec.  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 Sec.  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 Sec.  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 Sec.  
63.1283(d)(5)(ii). For sources required to meet the BTEX limit in 
accordance with Sec.  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 Sec.  
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.
* * * * *

[[Page 52835]]

    (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 Sec.  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 Sec.  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 Sec.  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 
Sec.  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 Sec.  
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 
Silonite-coated 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

[[Page 52836]]

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 Sec.  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 
Sec.  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 Sec.  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:

[[Page 52837]]

    (1) The inlet gas flow rate shall meet the range specified by the 
manufacturer. Flow rate shall be measured as specified in Sec.  
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 Sec.  
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:

Sec.  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 Sec.  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 Sec.  
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 Sec.  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 Sec.  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 Sec.  63.8(c)(1) and (c)(3); and
    (E) Ongoing reporting and recordkeeping procedures in accordance 
with provisions in Sec.  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 site-specific 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 Sec.  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

[[Page 52838]]

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 Sec.  
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 Sec.  
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 Sec.  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 Sec.  63.1282(d)(3) to demonstrate 
that the control device achieves the applicable performance 
requirements specified in Sec.  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 Sec.  63.1282(d)(4) to demonstrate 
that the control device achieves the applicable performance 
requirements specified in Sec.  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 Sec.  63.1282(g) to 
demonstrate that the control device achieves the applicable performance 
requirements specified in Sec.  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 Sec.  63.1282(d)(3) to demonstrate 
that the condenser achieves the applicable performance requirements in 
Sec.  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 Sec.  63.1282(d)(4)(i) to 
demonstrate that the condenser achieves the applicable performance 
requirements specified in Sec.  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 Sec.  63.1281(d)(1)(ii), an excursion 
occurs when average condenser efficiency

[[Page 52839]]

calculated according to the requirements specified in Sec.  
63.1282(f)(2)(iii) is less than 95.0 percent, as specified in Sec.  
63.1282(f)(3). For sources meeting Sec.  63.1281(f)(1), an excursion 
occurs when the 30-day average condenser efficiency calculated 
according to the requirements of Sec.  63.1282(f)(2)(iii) is less than 
the identified 30-day required percent reduction.
* * * * *
    (v) For control device whose model is tested under Sec.  63.1282(g) 
an excursion occurs when:
    (A) The inlet gas flow rate exceeds the maximum established during 
the test conducted under Sec.  63.1282(g).
    (B) Failure of the monthly visible emissions test conducted under 
Sec.  63.1282(h)(3) occurs.
    (8) * * *
    (i) * * *
    (A) During a malfunction when the affected facility is operated 
during such period in accordance with Sec.  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 Sec.  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:

Sec.  63.1284  Recordkeeping requirements.

* * * * *
    (b) * * *
    (3) Records specified in Sec.  63.10(c) for each monitoring system 
operated by the owner or operator in accordance with the requirements 
of Sec.  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 Sec.  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 Sec.  63.1275, records 
of the annual 30-day rolling average condenser efficiency determined 
under Sec.  63.1282(f) shall be kept in addition to the daily averages.
    (C) For a control device whose model is tested under Sec.  
63.1282(g), the records required in paragraph (g) of this section.
* * * * *
    (7) * * *
    (ix) Records identifying the carbon replacement schedule under 
Sec.  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 Sec.  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 Sec.  63.1282(g) to comply with Sec.  63.1281(d), 
(e)(3)(ii) and (f)(1):
    (1) All visible emission readings and flowrate measurements made 
during the compliance determination required by Sec.  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 
Sec.  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:

Sec.  63.1285  Reporting requirements.

* * * * *
    (b) * * *
    (1) The initial notifications required for existing affected 
sources under Sec.  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 Sec.  63.1270(d)(3) shall 
submit an initial notification required for existing affected sources 
under Sec.  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 Sec.  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

[[Page 52840]]

actions taken by an owner or operator during a malfunction of an 
affected source to minimize emissions in accordance with Sec.  
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 Sec.  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 Sec.  
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 Sec.  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 Sec.  
63.1282(g), an electronic copy of the performance test results shall be 
submitted via e-mail to PT@EPA.GOV">Oil_and_Gas_PT@EPA.GOV.
* * * * *
    (2) If a closed-vent system and a flare are used to comply with 
Sec.  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 Sec.  
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 Sec.  63.1281(d)(1), 
(e)(3)(ii), or (f)(1).
* * * * *
    (iv) For each carbon adsorber, the predetermined carbon replacement 
schedule as required in Sec.  63.1281(d)(5)(i).
* * * * *
    (10) The owner or operator shall submit the analysis prepared under 
Sec.  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 Sec.  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 Sec.  63.1282(g), the data listed 
under Sec.  63.1282(g)(8).
    (12) For each combustion control device model tested under Sec.  
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 Sec.  
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 Sec.  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 Sec.  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 Sec.  
63.1282(d)(3) conducted during the reporting period.
    (xi) For each carbon adsorber used to meet the control device 
requirements of Sec.  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 Sec.  63.1283(b) the records specified in Sec.  
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 
Sec.  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 Sec.  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:

Sec.  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 Sec. Sec.  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

* * * * *

[[Page 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
----------------------------------------------------------------------------------------------------------------
Sec.   63.1(a)(1)...................  Yes......................
Sec.   63.1(a)(2)...................  Yes......................
Sec.   63.1(a)(3)...................  Yes......................
Sec.   63.1(a)(4)...................  Yes......................
Sec.   63.1(a)(5)...................  No.......................  Section reserved.
Sec.   63.1(a)(6) through (a)(8)....  Yes......................
Sec.   63.1(a)(9)...................  No.......................  Section reserved.
Sec.   63.1(a)(10)..................  Yes......................
Sec.   63.1(a)(11)..................  Yes......................
Sec.   63.1(a)(12) through (a)(14)..  Yes......................
Sec.   63.1(b)(1)...................  No.......................  Subpart HHH specifies applicability.
Sec.   63.1(b)(2)...................  Yes......................
Sec.   63.1(b)(3)...................  No.......................
Sec.   63.1(c)(1)...................  No.......................  Subpart HHH specifies applicability.
Sec.   63.1(c)(2)...................  No.......................
Sec.   63.1(c)(3)...................  No.......................  Section reserved.
Sec.   63.1(c)(4)...................  Yes......................
Sec.   63.1(c)(5)...................  Yes......................
Sec.   63.1(d)......................  No.......................  Section reserved.
Sec.   63.1(e)......................  Yes......................
Sec.   63.2.........................  Yes......................  Except definition of major source is unique for
                                                                  this source category and there are additional
                                                                  definitions in subpart HHH.
Sec.   63.3(a) through (c)..........  Yes......................
Sec.   63.4(a)(1) through (a)(3)....  Yes......................
Sec.   63.4(a)(4)...................  No.......................  Section reserved.
Sec.   63.4(a)(5)...................  Yes......................
Sec.   63.4(b)......................  Yes......................
Sec.   63.4(c)......................  Yes......................
Sec.   63.5(a)(1)...................  Yes......................
Sec.   63.5(a)(2)...................  No.......................  Preconstruction review required only for major
                                                                  sources that commence construction after
                                                                  promulgation of the standard.
Sec.   63.5(b)(1)...................  Yes......................
Sec.   63.5(b)(2)...................  No.......................  Section reserved.
Sec.   63.5(b)(3)...................  Yes......................
Sec.   63.5(b)(4)...................  Yes......................
Sec.   63.5(b)(5)...................  Yes......................
Sec.   63.5(b)(6)...................  Yes......................
Sec.   63.5(c)......................  No.......................  Section reserved.
Sec.   63.5(d)(1)...................  Yes......................
Sec.   63.5(d)(2)...................  Yes......................
Sec.   63.5(d)(3)...................  Yes......................
Sec.   63.5(d)(4)...................  Yes......................
Sec.   63.5(e)......................  Yes......................
Sec.   63.5(f)(1)...................  Yes......................
Sec.   63.5(f)(2)...................  Yes......................
Sec.   63.6(a)......................  Yes......................
Sec.   63.6(b)(1)...................  Yes......................
Sec.   63.6(b)(2)...................  Yes......................
Sec.   63.6(b)(3)...................  Yes......................
Sec.   63.6(b)(4)...................  Yes......................
Sec.   63.6(b)(5)...................  Yes......................
Sec.   63.6(b)(6)...................  No.......................  Section reserved.
Sec.   63.6(b)(7)...................  Yes......................
Sec.   63.6(c)(1)...................  Yes......................
Sec.   63.6(c)(2)...................  Yes......................
Sec.   63.6(c)(3) and (c)(4)........  No.......................  Section reserved.
Sec.   63.6(c)(5)...................  Yes......................
Sec.   63.6(d)......................  No.......................  Section reserved.
Sec.   63.6(e)......................  Yes......................
Sec.   63.6(e)......................  Yes......................  Except as otherwise specified.
Sec.   63.6(e)(1)(i)................  No.......................  See Sec.   63.1274(h) for general duty
                                                                  requirement.
Sec.   63.6(e)(1)(ii)...............  No.......................
Sec.   63.6(e)(1)(iii)..............  Yes......................
Sec.   63.6(e)(2)...................  Yes......................
Sec.   63.6(e)(3)...................  No.......................
Sec.   63.6(f)(1)...................  No.......................
Sec.   63.6(f)(2)...................  Yes......................
Sec.   63.6(f)(3)...................  Yes......................
Sec.   63.6(g)......................  Yes......................
Sec.   63.6(h)......................  No.......................  Subpart HHH does not contain opacity or visible
                                                                  emission standards.
Sec.   63.6(i)(1) through (i)(14)...  Yes......................

[[Page 52842]]

 
Sec.   63.6(i)(15)..................  No.......................  Section reserved.
Sec.   63.6(i)(16)..................  Yes......................
Sec.   63.6(j)......................  Yes......................
Sec.   63.7(a)(1)...................  Yes......................
Sec.   63.7(a)(2)...................  Yes......................  But the performance test results must be
                                                                  submitted within 180 days after the compliance
                                                                  date.
Sec.   63.7(a)(3)...................  Yes......................
Sec.   63.7(b)......................  Yes......................
Sec.   63.7(c)......................  Yes......................
Sec.   63.7(d)......................  Yes......................
Sec.   63.7(e)(1)...................  No.......................
Sec.   63.7(e)(2)...................  Yes......................
Sec.   63.7(e)(3)...................  Yes......................
Sec.   63.7(e)(4)...................  Yes......................
Sec.   63.7(f)......................  Yes......................
Sec.   63.7(g)......................  Yes......................
Sec.   63.7(h)......................  Yes......................
Sec.   63.8(a)(1)...................  Yes......................
Sec.   63.8(a)(2)...................  Yes......................
Sec.   63.8(a)(3)...................  No.......................  Section reserved.
Sec.   63.8(a)(4)...................  Yes......................
Sec.   63.8(b)(1)...................  Yes......................
Sec.   63.8(b)(2)...................  Yes......................
Sec.   63.8(b)(3)...................  Yes......................
Sec.   63.8(c)(1)...................  Yes......................
63.8(c)(1)(i).......................  No.......................
Sec.   63.8(c)(1)(ii)...............  Yes......................
Sec.   63.8(c)(1)(iii)..............  Pending..................
Sec.   63.8(c)(2)...................  Yes......................
Sec.   63.8(c)(3)...................  Yes......................
Sec.   63.8(c)(4)...................  No.......................
Sec.   63.8(c)(5) through (c)(8)....  Yes......................
Sec.   63.8(d)......................  Yes......................
Sec.   63.8(d)(3)...................  Yes......................  Except for last sentence, which refers to an
                                                                  SSM plan. SSM plans are not required.
Sec.   63.8(e)......................  Yes......................  Subpart HHH does not specifically require
                                                                  continuous emissions monitor performance
                                                                  evaluations, however, the Administrator can
                                                                  request that one be conducted.
Sec.   63.8(f)(1) through (f)(5)....  Yes......................
Sec.   63.8(f)(6)...................  No.......................  Subpart HHH does not require continuous
                                                                  emissions monitoring.
Sec.   63.8(g)......................  No.......................  Subpart HHH specifies continuous monitoring
                                                                  system data reduction requirements.
Sec.   63.9(a)......................  Yes......................
Sec.   63.9(b)(1)...................  Yes......................
Sec.   63.9(b)(2)...................  Yes......................  Existing sources are given 1 year (rather than
                                                                  120 days) to submit this notification.
Sec.   63.9(b)(3)...................  Yes......................
Sec.   63.9(b)(4)...................  Yes......................
Sec.   63.9(b)(5)...................  Yes......................
Sec.   63.9(c)......................  Yes......................
Sec.   63.9(d)......................  Yes......................
Sec.   63.9(e)......................  Yes......................
Sec.   63.9(f)......................  No.......................
Sec.   63.9(g)......................  Yes......................
Sec.   63.9(h)(1) through (h)(3)....  Yes......................
Sec.   63.9(h)(4)...................  No.......................  Section reserved.
Sec.   63.9(h)(5) and (h)(6)........  Yes......................
Sec.   63.9(i)......................  Yes......................
Sec.   63.9(j)......................  Yes......................
Sec.   63.10(a).....................  Yes......................
Sec.   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.
Sec.   63.10(b)(2)..................  Yes......................
Sec.   63.10(b)(2)(i)...............  No.......................
Sec.   63.10(b)(2)(ii)..............  No.......................  See Sec.   63.1284(f) for recordkeeping of
                                                                  occurrence, duration, and actions taken during
                                                                  malfunction.
Sec.   63.10(b)(2)(iii).............  Yes......................
Sec.   63.10(b)(2)(iv) through        No.......................
 (b)(2)(v).
Sec.   63.10(b)(2)(vi) through        Yes......................
 (b)(2)(xiv).
Sec.   63.10(b)(3)..................  No.......................
Sec.   63.10(c)(1)..................  Yes......................
Sec.   63.10(c)(2) through (c)(4)...  No.......................  Sections reserved.
Sec.   63.10(c)(5) through (c)(8)...  Yes......................
Sec.   63.10(c)(9)..................  No.......................  Section reserved.

[[Page 52843]]

 
Sec.   63.10(c)(10) and (c)(11).....  No.......................  See Sec.   63.1284(f)for recordkeeping of
                                                                  malfunctions
Sec.   63.10(c)(12) through (c)(14).  Yes......................
Sec.   63.10(c)(15).................  No.......................
Sec.   63.10(d)(1)..................  Yes......................
Sec.   63.10(d)(2)..................  Yes......................
Sec.   63.10(d)(3)..................  Yes......................
Sec.   63.10(d)(4)..................  Yes......................
Sec.   63.10(d)(5)..................  No.......................  See Sec.   63.1285(b)(6) for reporting of
                                                                  malfunctions.
Sec.   63.10(e)(1)..................  Yes......................
Sec.   63.10(e)(2)..................  Yes......................
Sec.   63.10(e)(3)(i)...............  Yes......................  Subpart HHH requires major sources to submit
                                                                  Periodic Reports semi-annually.
Sec.   63.10(e)(3)(i)(A)............  Yes......................
Sec.   63.10(e)(3)(i)(B)............  Yes......................
Sec.   63.10(e)(3)(i)(C)............  No.......................  Subpart HHH does not require quarterly
                                                                  reporting for excess emissions.
Sec.   63.10(e)(3)(ii) through        Yes......................
 (e)(3)(viii).
Sec.   63.10(f).....................  Yes......................
Sec.   63.11(a) and (b).............  Yes......................
Sec.   63.11(c), (d), and (e).......  Yes......................
Sec.   63.12(a) through (c).........  Yes......................
Sec.   63.13(a) through (c).........  Yes......................
Sec.   63.14(a) and (b).............  Yes......................
Sec.   63.15(a) and (b).............  Yes.                       ...............................................
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[FR Doc. 2011-19899 Filed 8-22-11; 8:45 am]
BILLING CODE 6560-50-P