[Federal Register Volume 76, Number 163 (Tuesday, August 23, 2011)]
[Proposed Rules]
[Pages 52738-52843]
[FR Doc No: 2011-19899]

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

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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<EMAIL_ADDRESS>Include Docket ID Number
EPA-HQ-OAR-2010-0505 in the subject line of the message.
     Facsimile:<PHONE_NUMBER>.
     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:<PHONE_NUMBER>; facsimile number:
(919) 685-3200; e-mail address<EMAIL_ADDRESS>
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?

    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

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<PHONE_NUMBER> 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

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

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.
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    \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

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

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,

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

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

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

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://

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

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

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-

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

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

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