[Federal Register Volume 77, Number 159 (Thursday, August 16, 2012)]
[Rules and Regulations]
[Pages 49489-49600]
[FR Doc No: 2012-16806]

Vol. 77

Thursday,

No. 159

August 16, 2012

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; Final
Rule

Federal Register / Vol. 77 , No. 159 / Thursday, August 16, 2012 /
Rules and Regulations

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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Parts 60 and 63

[EPA-HQ-OAR-2010-0505; FRL-9665-1]
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: Final rule.

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SUMMARY: This action finalizes the review of new source performance
standards for the listed oil and natural gas source category. In this
action the EPA revised the new source performance standards for
volatile organic compounds from leaking components at onshore natural
gas processing plants and new source performance standards for sulfur
dioxide emissions from natural gas processing plants. The EPA also
established standards for certain oil and gas operations not covered by
the existing standards. In addition to the operations covered by the
existing standards, the newly established standards will regulate
volatile organic compound emissions from gas wells, centrifugal
compressors, reciprocating compressors, pneumatic controllers and
storage vessels. This action also finalizes the residual risk and
technology review for the Oil and Natural Gas Production source
category and the Natural Gas Transmission and Storage source category.
This action includes revisions to the existing leak detection and
repair requirements. In addition, the EPA has established in this
action emission limits reflecting maximum achievable control technology
for certain currently uncontrolled emission sources in these source
categories. This action also includes modification and addition of
testing and monitoring and related notification, recordkeeping and
reporting requirements, as well as other minor technical revisions to
the national emission standards for hazardous air pollutants. This
action finalizes revisions to the regulatory provisions related to
emissions during periods of startup, shutdown and malfunction.

DATES: This final rule is effective on October 15, 2012. The
incorporation by reference of certain publications listed in this rule
is approved by the Director of the Federal Register as of October 15,
2012.

ADDRESSES: The EPA has established a docket for this action under
Docket ID. No. EPA-HQ-OAR-2010-0505. All documents in the docket are
listed on the http://www.regulations.gov Web site. Although listed in
the index, some information is not publicly available, e.g.,
confidential business information or other information whose disclosure
is restricted by statute. Certain other material, such as copyrighted
material, is not placed on the Internet and will be publicly available
only in hard copy form. Publicly available docket materials are
available either electronically through http://www.regulations.gov or
in hard copy at the EPA's Docket Center, Public Reading Room, EPA West
Building, Room Number 3334, 1301 Constitution Avenue NW., Washington,
DC 20004. This Docket Facility is open from 8:30 a.m. to 4:30 p.m.
Eastern Standard Time, Monday through Friday, excluding legal holidays.
The telephone number for the Public Reading Room is<PHONE_NUMBER>, and
the telephone number for the Air Docket is<PHONE_NUMBER>.

FOR FURTHER INFORMATION CONTACT: For further information about this
final action, contact Mr. Bruce Moore, Sector Policies and Programs
Division (E143-05), Office of Air Quality and Standards, Environmental
Protection Agency, Research Triangle Park, North Carolina 27711,
telephone number:<PHONE_NUMBER>; facsimile number:<PHONE_NUMBER>;
email address<EMAIL_ADDRESS>For additional contact information,
see the following SUPPLEMENTARY INFORMATION section.

SUPPLEMENTARY INFORMATION: For specific information regarding risk
assessment and exposure modeling methodology, contact Mr. Mark Morris,
Health and Environmental Impacts Division (C504-06), Office of Air
Quality Planning and Standards, U.S. Environmental Protection Agency,
Research Triangle Park, NC 27711; telephone number<PHONE_NUMBER>; fax
number:<PHONE_NUMBER>; and email address<EMAIL_ADDRESS>    Organization of This Document. The information presented in this
preamble is organized as follows:

I. Preamble Acronyms and Abbreviations
II. General Information
    A. Executive Summary
    B. Does this action apply to me?
    C. What are the emission sources affected by this action?
    D. Where can I get a copy of this document?
    E. Judicial Review
III. Background Information on the NSPS and NESHAP
    A. What are the statutory authorities for the NSPS and NESHAP?
    B. What is the litigation history?
    C. What is the sector-based approach?
    D. What are the health effects of pollutants emitted from the
oil and natural gas sector?
IV. Summary of the Final NSPS Rule
    A. What are the final actions relative to the NSPS for the Crude
Oil and Natural Gas Production source category?
    B. What are the effective and compliance dates for the final
NSPS?
V. Summary of the Significant Changes to the NSPS Since Proposal
    A. Gas Well Affected Facilities
    B. Centrifugal and Reciprocating Compressor Affected Facilities
    C. Pneumatic Controller Affected Facilities
    D. Storage Vessel Affected Facilities
    E. Equipment Leaks Affected Facilities and Sweetening Unit
Affected Facilities at Onshore Natural Gas Processing Plants
    F. Changes to Notification, Recordkeeping and Reporting
Requirements
VI. Summary of the Final NESHAP Rules
    A. What are the final rule actions relative to the Oil and
Natural Gas Production (subpart HH) source category?
    B. What are the final rule amendments for the Natural Gas
Transmission and Storage (subpart HHH) source category?
    C. What is the effective date of this final rule and compliance
dates for the standards?
VII. Summary of the Significant Changes to the NESHAP Since Proposal
    A. What are the significant changes since proposal for the Oil
and Natural Gas Production (subpart HH) source category?
    B. What are the significant changes since proposal for the
Natural Gas Transmission and Storage (subpart HHH) source category?
VIII. Compliance Related Issues Common to the NSPS and NESHAP
    A. How do the rules address startup, shutdown and malfunction?
    B. How do the NSPS and NESHAP provide for compliance assurance?
    C. What are the requirements for submission of performance test
data to the EPA?
IX. Summary of Significant NSPS Comments and Responses
    A. Major Comments Concerning Applicability
    B. Major Comments Concerning Well Completions
    C. Major Comments Concerning Pneumatic Controllers
    D. Major Comments Concerning Compressors
    E. Major Comments Concerning Storage Vessels
    F. Major Comments Concerning Notification, Recordkeeping and
Reporting Requirements
X. Summary of Significant NESHAP Comments and Responses
    A. Major Comments Concerning Previously Unregulated Sources
    B. Major Comments Concerning the Risk Review
    C. Major Comments Concerning the Technology Review

    D. Major Comments Concerning Notification, Recordkeeping and
Reporting Requirements
XI. What are the cost, environmental and economic impacts of the
final NESHAP and NSPS amendments?
    A. What are the air impacts?
    B. What are the energy impacts?
    C. What are the cost impacts?
    D. What are the economic impacts?
    E. What are the benefits of this final rule?
XII. Statutory and Executive Order Reviews
    A. Executive Order 12866: Regulatory Planning and Review and
Executive Order 13563: Improving Regulation and Regulatory Review
    B. Paperwork Reduction Act
    C. Regulatory Flexibility Act
    D. Unfunded Mandates Reform Act
    E. Executive Order 13132: Federalism
    F. Executive Order 13175: Consultation and Coordination With
Indian Tribal Governments
    G. Executive Order 13045: Protection of Children From
Environmental Health Risks and Safety Risks
    H. Executive Order 13211: Actions Concerning Regulations That
Significantly Affect Energy Supply, Distribution, or Use
    I. National Technology Transfer and Advancement Act
    J. Executive Order 12898: Federal Actions To Address
Environmental Justice in Minority Populations and Low-Income
Populations
    K. Congressional Review Act

I. 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:

API American Petroleum Institute
BACT Best Available Control Technology
BDT Best Demonstrated Technology
bpd Barrels Per Day
BMP Best Management Practice
BSER Best System of Emission Reduction
BTEX Benzene, Ethylbenzene, Toluene and Xylene
CAA Clean Air Act
CBM Coal Bed Methane
CDX Central Data Exchange
CEDRI Compliance and Emissions Data Reporting Interface
CFR Code of Federal Regulations
CO Carbon Monoxide
CO2 Carbon Dioxide
CO2e Carbon Dioxide Equivalent
DOE United States Department of Energy
e-GGRT Electronic Greenhouse Gas Reporting Tool
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 NEI code 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
PSIA Pounds per Square Inch Absolute
PTE Potential to Emit
QA Quality Assurance
RACT Reasonably Available Control Technology
RBLC RACT/BACT/LAER Clearinghouse
REC Reduced Emissions Completions
REL California EPA 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. Executive Summary

1. Purpose of the Regulatory Action
    Responding to the requirements of a consent decree, this action
finalizes several rules that apply to the oil and gas production
industry and significantly reduce emissions of air pollutants. More
particularly, the action finalizes:
     New source performance standards (NSPS) for the Crude Oil
and Natural Gas Production and onshore natural gas processing plant
source category. The EPA reviewed two existing NSPS for onshore natural
gas processing plant source category under section 111(b) of the Clean
Air Act (CAA). This action improves the existing NSPS and finalizes
standards for certain crude oil and natural gas sources that are not
covered by existing NSPS for this sector.
     National Emissions Standards for Hazardous Air Pollutants
(NESHAP) for the Oil and Natural Gas Production source category and the
Natural Gas Transmission and Storage source category. The EPA conducted
risk and technology reviews (RTR) for these rules under section 112 of
the CAA. In addition, the EPA has established emission limits for
certain currently uncontrolled emission sources in these

source categories. These limits reflect maximum achievable control
technology (MACT).
2. Summary of the Major Provisions of the Regulatory Actions
    New Source Performance Standards (NSPS). The newly established NSPS
for the Crude Oil and Natural Gas Production source category regulate
volatile organic compound (VOC) emissions from gas wells, centrifugal
compressors, reciprocating compressors, pneumatic controllers, storage
vessels and leaking components at onshore natural gas processing
plants, as well as sulfur dioxide (SO2) emissions from
onshore natural gas processing plants. This rule sets cost-effective
performance standards for:
    Gas wells. The rule covers any gas well that is ``an onshore well
drilled principally for production of natural gas.'' Oil wells (wells
drilled principally for the production of crude oil) are not subject to
this rule. For fractured and refractured gas wells, the rule generally
requires owners/operators to use reduced emissions completions, also
known as ``RECs'' or ``green completions,'' to reduce VOC emissions
from well completions. To achieve these VOC reductions, owners and/or
operators may use RECs or completion combustion devices, such as
flaring, until January 1, 2015; as of January 1, 2015, owners and/or
operators must use RECs and a completion combustion device. The rule
does not require RECs where their use is not feasible, as specified in
the rule. See sections IX.A and IX.B of this preamble for further
discussion.
    Storage vessels. Individual storage vessels in the oil and natural
gas production segment and the natural gas processing, transmission and
storage segments with emissions equal to or greater than 6 tons per
year (tpy) must achieve at least 95.0 percent reduction in VOC
emissions. See section IX.E of this preamble for further discussion.
    Certain controllers. The rule sets a natural gas bleed rate limit
of 6 scfh for individual, continuous bleed, natural gas-driven
pneumatic controllers located between the wellhead and the point at
which the gas enters the transmission and storage segment. For
individual, continuous bleed, natural gas-driven pneumatic controllers
located at natural gas processing plants, the rule sets a natural gas
bleed limit of zero scfh. See section IX.C of this preamble for further
discussion.
    Certain compressors. The rule requires a 95.0 percent reduction of
VOC emissions from wet seal centrifugal compressors located between the
wellhead and the point at which the gas enters the transmission and
storage segment. The rule also requires measures intended to reduce VOC
emissions from reciprocating compressors located between the wellhead
and the point where natural gas enters the natural gas transmission and
storage segment. Owners and/or operators of these compressors must
replace the rod packing based on specified usage or time. See section
IX.D of this preamble for further discussion.
    For onshore natural gas processing plants, this final action
revises the existing NSPS requirements for leak detection and repair
(LDAR) to reflect the procedures and leak thresholds established in the
NSPS for Equipment Leaks of VOCs in the Synthetic Organic Chemicals
Manufacturing Industry. This final action also revises the existing
NSPS requirements for SO2 emission reductions 99.8 percent
to 99.9 percent based on reanalysis of the original data.
    National Emissions Standards for Hazardous Air Pollutants (NESHAP).
This action also revises the NESHAP for glycol dehydration unit process
vents and leak detection and repair (LDAR) requirements. In the final
rule for major sources at oil and natural gas production facilities, we
have lowered the leak definition for valves at natural gas processing
plants to 500 parts per million (ppm) and thus require the application
of LDAR procedures at this level. In this final rule, we also have
established MACT standards for ``small'' glycol dehydration units,
which were unregulated under the initial NESHAP. Covered glycol
dehydrators are those with an actual annual average natural gas flow
rate less than 85,000 standard cubic meters per day (scmd) or actual
average benzene emissions less than 1 ton per year (tpy), and they must
meet unit-specific limits for benzene, ethylbenzene, toluene and xylene
(BTEX).
    In the final rule for major sources at natural gas transmission and
storage facilities, we have established MACT standards for ``small''
glycol dehydrators also not regulated under the initial NESHAP. Covered
glycol dehydrators are those with an actual annual average natural gas
flow rate less than 283,000 scmd or actual average benzene emissions
less than 0.90 Mg/yr, and they must meet unit-specific BTEX emission
limits. v. See sections VII and X of this preamble for further
discussion of both standards.
3. Costs and Benefits
    Table 1 summarizes the costs and benefits of this action. See
section XI of this preamble for further discussion.

Table 1--Summary of the Monetized Benefits, Social Costs and Net Benefits for the Final Oil And Natural Gas NSPS
                                          and NESHAP Amendments in 2015
                                             [Millions of 2008$] \1\
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                                                                                Final NSPS and NESHAP
                                              Final NSPS        Final NESHAP amendments    amendments combined
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Total Monetized Benefits \2\.........  N/A....................  N/A....................  N/A.
Total Costs \3\......................  -$15 million...........  $3.5 million...........  -$11 million.
Net Benefits.........................  N/A....................  N/A....................  N/A.
Non-monetized Benefits \4\...........  11,000 tons of HAP.....  670 tons of HAP........  12,000 tons of HAP.
                                       190,000 tons of VOC....  1,200 tons of VOC......  190,000 tons of VOC.
                                       1.0 million tons of      420 tons of methane....  1.0 million tons of
                                        methane.                                          methane.
                                      --------------------------------------------------------------------------
                                       Health effects of HAP exposure.
                                       Health effects of PM2.5 and ozone exposure.
                                       Visibility impairment.
                                       Vegetation effects.
                                       Climate effects.
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\1\ All estimates are for the implementation year (2015).

\2\ While we expect that these avoided emissions will result in improvements in air quality and reductions in
  health effects associated with HAP, ozone and particulate matter (PM), as well as climate effects associated
  with methane, we have determined that quantification of those benefits and co-benefits cannot be accomplished
  for this rule in a defensible way. This is not to imply that there are no benefits or co-benefits of the
  rules; rather, it is a reflection of the difficulties in modeling the direct and indirect impacts of the
  reductions in emissions for this industrial sector with the data currently available.
\3\ The engineering compliance costs are annualized using a 7-percent discount rate. The negative cost for the
  final NSPS reflects the inclusion of revenues from additional natural gas and hydrocarbon condensate recovery
  that are estimated as a result of the NSPS. Possible explanations for why there appear to be negative cost
  control technologies are discussed in the engineering costs analysis section in the Regulatory Impact Analysis
  (RIA).
\4\ For the NSPS, reduced exposure to HAP and climate effects are co-benefits. For the NESHAP, reduced VOC
  emissions, PM2.5 and ozone exposure, visibility and vegetation effects and climate effects are co-benefits.
  The specific control technologies for the final NSPS are anticipated to have minor secondary disbenefits,
  including an increase of 1.1 million tons of carbon dioxide (CO2), 550 tons of nitrogen oxides (NOX), 19 tons
  of PM, 3,000 tons of carbon monoxide (CO) and 1,100 tons of total hydrocarbons (THC), as well as emission
  reductions associated with the energy system impacts. The specific control technologies for the NESHAP are
  anticipated to have minor secondary disbenefits, but the EPA was unable to estimate the secondary disbenefits.
  The net CO2-equivalent emission reductions are 18 million metric tons.

B. Does this action apply to me?

    The regulated categories and entities potentially affected
    by the final standards are shown in Table 2 of this preamble.

      Table 2--Industrial Source Categories Affected by This Action
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                                                  Examples of regulated
            Category             NAICS code \1\          entities
------------------------------------------------------------------------
Industry.......................          211111  Crude Petroleum and
                                                  Natural Gas
                                                  Extraction.
                                         211112  Natural Gas Liquid
                                                  Extraction.
                                         221210  Natural Gas
                                                  Distribution.
                                         486110  Pipeline Distribution
                                                  of Crude Oil.
                                         486210  Pipeline Transportation
                                                  of Natural Gas.
Federal government.............  ..............  Not affected.
State/local/tribal government..  ..............  Not affected.
------------------------------------------------------------------------
\1\ North American Industry Classification System.

    This table is not intended to be exhaustive, but rather is meant to
provide a guide for readers regarding entities likely to be affected by
this action. If you have any questions regarding the applicability of
this action to a particular entity, consult either the air permitting
authority for the entity or your EPA regional representative as listed
in 40 CFR 60.4 or 40 CFR 63.13 (General Provisions).

C. What are the emission sources affected by this action?

1. What are the emission sources affected by the NSPS?
    The emission sources affected by the NSPS include well completions,
pneumatic controllers, equipment leaks from natural gas processing
plants, sweetening units at natural gas processing plants,
reciprocating compressors, centrifugal compressors and storage vessels
which are constructed, modified or reconstructed after August 23, 2011.
Well completions subject to the NSPS are limited to the flowback period
following hydraulic fracturing operations at a gas well affected
facility. These completions include those conducted at newly drilled
and fractured wells, as well as completions conducted following
refracturing operations that may occur at various times over the life
of the well. Pneumatic controllers affected by the NSPS include
continuous bleed, natural gas-driven pneumatic controllers with a
natural gas bleed rate greater than 6 scfh and which commenced
construction after August 23, 2011, in the oil and natural gas
production segment (except for gas processing plants) and continuous
bleed natural gas-driven pneumatic controllers which commenced
construction after August 23, 2011, at natural gas processing plants.
The NSPS applies to centrifugal compressors with wet seals and
reciprocating compressors located in the natural gas production and
processing segments. The NSPS also applies to equipment leaks from
onshore natural gas processing plants and to storage vessels located in
the oil and natural gas production segment, the natural gas processing
segment and the natural gas transmission and storage segment. The NSPS
also affects sweetening units located onshore that process natural gas
from onshore or offshore wells.
2. What are the emission sources affected by the NESHAP?
    The emission sources that are affected by the Oil and Natural Gas
Production NESHAP (40 CFR part 63, subpart HH) or the Natural Gas
Transmission and Storage NESHAP (40 CFR part 63, subpart HHH) include
glycol dehydrators and equipment leaks.

D. Where can I get a copy of this document?

    In addition to being available in the docket, an electronic copy of
this action will also be available on the World Wide Web (WWW).
Following signature by the Administrator, a copy of the 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 RTR Web site at
http://www.epa.gov/ttn/vatw/rrisk/oarpg.html. This information includes
the most recent version of the rule, source category descriptions,
detailed emissions and other data were used as inputs to the risk
assessments.

E. Judicial Review

    Under CAA section 307(b)(1), judicial review of this final rule is
available only by filing a petition for review in the United States
Court of Appeals for the District of Columbia Circuit by October 15,
2012. Under CAA section 307(d)(7)(B), only an objection to this final
rule that was raised with reasonable specificity during the period for
public comment (including any public hearing) can be raised during
judicial review. This section also provides a mechanism for the EPA to
convene a proceeding for reconsideration ``[i]f the person raising an
objection can demonstrate to the Administrator that it was
impracticable

to raise such objection within [the period for public comment] or if
the grounds for such objection arose after the period for public
comment (but within the time specified for judicial review) and if such
objection is of central relevance to the outcome of the rule[.]'' Any
person seeking to make such a demonstration to us should submit a
Petition for Reconsideration to the Office of the Administrator,
Environmental Protection Agency, Room 3000, Ariel Rios Building, 1200
Pennsylvania Ave. NW., Washington, DC 20004, with a copy to the person
listed in the preceding FOR FURTHER INFORMATION CONTACT section, and
the Associate General Counsel for the Air and Radiation Law Office,
Office of General Counsel (Mail Code 2344A), Environmental Protection
Agency, 1200 Pennsylvania Ave. NW., Washington, DC 20004. Note, under
CAA section 307(b)(2), the requirements established by this final rule
may not be challenged separately in any civil or criminal proceedings
brought by the EPA to enforce these requirements.

III. Background Information on the NSPS and NESHAP

A. What are the statutory authorities for the NSPS and NESHAP?

1. What is the statutory authority for the NSPS?
    Section 111 of the 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. Whereas CAA section 112 standards
are issued for new and existing stationary sources, standards of
performance are issued for new and modified stationary sources. These
standards are referred to as 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.
However, the Administrator need not review any such standard if 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 authority 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
BSER 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 select any control measures that will meet the
emission limits. Upon promulgation, an NSPS becomes a national standard
to which all new sources must comply.
2. What is the statutory authority for the NESHAP?
    Section 112 of the CAA establishes a two-stage regulatory process
to address emissions of 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 NESHAP for those sources. ``Major
sources'' are those that emit or have the potential to emit (PTE) 10
tpy or more of a single HAP or 25 tpy or more of any combination of
HAP. For major sources, the technology-based emission 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 MACT
standards.
    MACT standards are set 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
sections 112(d)(2)(A)-(E). A 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 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. CAA section
112(f)(2) 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 must be set (unless a more
stringent standard is required to prevent an adverse environmental
effect, taking into consideration costs, energy, safety and other
relevant factors).
    If the MACT standards for HAP that are ``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.''). As mentioned, the EPA must also adopt more stringent
standards, if necessary, to prevent an adverse environmental effect,\1\
but must consider cost, energy, safety and other relevant factors in
doing so.
---------------------------------------------------------------------------

    \1\ ``Adverse environmental effect'' is defined in CAA section
112(a)(7) as any significant and widespread adverse effect, which
may be reasonably anticipated to wildlife, aquatic life or natural
resources, including adverse impacts on populations of endangered or
threatened species or significant degradation of environmental
qualities over broad areas.
---------------------------------------------------------------------------

    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 has concluded that the EPA's
interpretation of CAA section 112(f)(2) is a reasonable one. See NRDC
v. EPA, 529 F.3d at 1083 (``[S]ubsection 112(f)(2)(B) expressly
incorporates the EPA's interpretation of the Clean Air Act from the
Benzene standard, complete with a citation to the Federal Register'').
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 in the Residual Risk Report to Congress 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 are 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). See 54 FR 38046.

B. What is the litigation history?

    On January 14, 2009, pursuant to section 304(a)(2) of the CAA,
WildEarth Guardians and the San Juan Citizens Alliance filed a
complaint in the United States District Court for the District of
Columbia and alleged 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 5,
2010, the Court entered a consent decree that, as successively
modified, required the EPA to sign by July 28, 2011,\2\ 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 April 3, 2012. On April 2, 2012, the consent decree was modified to
change the date for final action to no later than April 17, 2012.
---------------------------------------------------------------------------

    \2\ On April 27, 2011, pursuant to paragraph 10(a) of the
Consent Decree, the parties filed with the Court a written
stipulation to extend the proposal date from January 31, 2011, to
July 28, 2011, and the final action date from November 30, 2011, to
February 28, 2012. On October 28, 2011, pursuant to paragraph 10(a)
of the Consent Decree, the parties filed with the Court a written
stipulation to extend the final action date from February 28, 2012,
to April 3, 2012.
---------------------------------------------------------------------------

C. What is the sector-based approach?

    Sector-based approaches are based on integrated assessments of
industrial operations 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, for example the NSPS and NESHAP, 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 pollutants, 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 streamlines the monitoring, recordkeeping and reporting
requirements, thus, reducing administrative and compliance complexities
associated with complying with multiple regulations. In addition, the
sector-based approach in this rule promotes a comprehensive control
strategy that maximizes the co-control of multiple regulated pollutants
while obtaining emission reductions as co-benefits.

D. What are the health effects of pollutants emitted from the oil and
natural gas sector?

    The final oil and natural gas sector NSPS and NESHAP amendments are
expected to result in significant reductions in existing emissions and
prevent new emissions from expansions of this industry. These emissions
include HAP, VOC (a precursor to both PM2.5 and ozone
formation) and methane (a GHG and a precursor to global ozone
formation). These emissions are associated with substantial health
effects, welfare effects and climate effects. One HAP of particular
concern from the oil and natural gas sector is benzene, which is a
known human carcinogen. PM2.5 is associated with health
effects, including premature mortality for adults and infants,
cardiovascular morbidity, such as heart attacks, hospital admissions
and respiratory morbidity such as asthma attacks, acute and chronic
bronchitis, hospital and emergency room visits, work loss days,
restricted activity days and respiratory symptoms, as well as
visibility impairment. Ozone is associated with health effects,
including hospital and emergency department visits, school loss days
and premature mortality, as well as injury to vegetation and climate
effects.

IV. Summary of the Final NSPS Rule

A. What are the final actions relative to the NSPS for the Crude Oil
and Natural Gas Production source category?

    We are revising the existing NSPS, which regulate VOC emissions
from equipment leaks and SO2 emissions from sweetening units
at onshore gas processing plants. In addition, we are promulgating
standards for several new oil and natural gas affected facilities. The
final standards apply to affected facilities that commence
construction, reconstruction or modification after August 23, 2011, the
date of the proposed rule.
    The listed Crude Oil and Natural Gas Production source category
covers, at a minimum, those operations for which we are establishing
standards in this final rule. Table 3 summarizes the 40 CFR part 60,
subpart OOOO standards. Further discussion of these changes may

be found below in this section and in sections V and IX of this
preamble.

                       Table 3--Summary of 40 CFR Part 60, Subpart OOOO Emission Standards
----------------------------------------------------------------------------------------------------------------
         Affected facility                  Pollutant                   Standard              Compliance dates
----------------------------------------------------------------------------------------------------------------
Hydraulically fractured wildcat and  VOC....................  Route flowback emissions to  October 15, 2012.
 delineation wells.                                            completion combustion
                                                               device.
Hydraulically fractured low          VOC....................  Route flowback emissions to  October 15, 2012.
 pressure wells, non-wildcat and                               completion combustion
 non-delineation wells.                                        device.
All other hydraulically fractured    VOC....................  Route flowback emissions to  Prior to January 1,
 gas wells.                                                    completion combustion        2015.
                                                               device.
All other hydraulically fractured    VOC....................  Use REC and route flowback   On or after January
 gas wells.                                                    emissions to completion      1, 2015.
                                                               combustion device.
Centrifugal compressors with wet     VOC....................  Reduce emissions by 95       October 15, 2012.
 seals.                                                        percent.
Reciprocating compressors..........  VOC....................  Change rod packing after     October 15, 2012.
                                                               26,000 hours or after 36
                                                               months.
Continuous bleed natural gas-driven  VOC....................  Natural gas bleed rate of    October 15, 2012.
 pneumatic controllers at natural                              zero.
 gas processing plants.
Continuous bleed natural gas-driven  VOC....................  Natural gas bleed rate less  October 15, 2013.
 pneumatic controllers with a bleed                            than 6 scfh.
 rate greater than 6 scfh between
 wellhead and natural gas
 processing plant or oil pipeline.
Storage vessels with VOC emissions   VOC....................  Reduce emissions by 95       October 15, 2013.
 equal to or greater than 6 tpy.                               percent.
Equipment leaks at onshore natural   VOC....................  LDAR program...............  October 15, 2012.
 gas processing plants.
Sweetening units at onshore natural  SO2....................  Reduce SO2 emissions based   October 15, 2012.
 gas processing plants.                                        on sulfur feed rate and
                                                               sulfur content of acid gas.
----------------------------------------------------------------------------------------------------------------

1. Standards for Gas Well Affected Facilities
    We are finalizing operational standards for completions of
hydraulically fractured and refractured gas wells. For purposes of this
rule, well completion is defined as the flowback period beginning after
hydraulic fracturing and ending with either well shut in or when the
well continuously flows to the flow line or to a storage vessel for
collection, whichever occurs first. The final rule applies to three
subcategories of fractured and refractured gas wells for which well
completion operations are conducted: (1) Wildcat (exploratory) and
delineation gas wells; (2) non-wildcat and non-delineation gas wells
for which the reservoir pressure is insufficient for a REC, commonly
referred to as a ``green completion,'' to be performed, as determined
by a simple calculation involving reservoir pressure, well depth and
flow line pressure at the sales meter (we refer to these wells as ``low
pressure gas wells'') and (3) other fractured and refractured gas
wells. For subcategory (3) wells, each well completion operation begun
on or after January 1, 2015, must employ REC in combination with use of
a completion combustion device to control gas not suitable for entering
the flow line (we refer to this as REC with combustion). For well
completion operations at subcategory (1) wells (exploratory and
delineation gas wells), subcategory (2) wells (low pressure gas wells)
and for well completion operations begun prior to January 1, 2015, at
subcategory (3) gas wells, the final rule requires the control of
emissions using either REC with combustion or just a completion
combustion device. Owners and operators are encouraged to use REC with
combustion during this period.
    Well completions subject to the standards are gas well completions
following hydraulic fracturing and refracturing 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. As we explained
in the proposal preamble, a completion operation associated with
refracturing performed at a well is considered a modification under CAA
section 111(a), because physical change occurs to the well resulting in
emissions increases during the refracturing and completion operation.
In response to comment, we further clarify this point in the final
rule, including providing a specific modification provision for well
completions in lieu of the General Provisions in 40 CFR 60.14. For a
more detailed explanation, please see section IX.A of this preamble.
The modification determination and resulting applicability of NSPS to
the completion operation following refracturing of gas wells is limited
strictly to the gas well affected facility and does not by itself
trigger applicability 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
(that is, such equipment is not part of the affected facility).
    The final rule provides that uncontrolled well completions
conducted on gas wells that are subsequently refractured on or after
the effective date of this rule are modifications and are subject to
the NSPS. However, gas wells that undergo completion following
refracturing are not considered modified and, as a result, are not
affected facilities under the NSPS if the completion operation is
conducted with the use, immediately upon flowback, of emission control
techniques otherwise required on or after January 1, 2015, for new
wells and satisfies other requirements, including notification,
recordkeeping and reporting requirements.
    In the final rule, we provide for a streamlined notification
process for well completions at gas well affected facilities consisting
of an email pre-notification no later than 2 days in advance of
impending completion operations. The email must include information
that had been part of the 30-day advance notification, as described in
the proposed rule, including contact information for the owner and
operator, well identification, geographic

coordinates of the well and planned date of the beginning of flowback.
    In the final rule, the recordkeeping and reporting requirements for
well completions also provide for a streamlining option that owners and
operators may choose in lieu of the standard annual reporting
requirements. The standard annual report must include copies of all
well completion records for each gas well affected facility for which a
completion operation was performed during the reporting period. The
alternative, streamlined annual report for gas well affected facilities
requires submission of a list, with identifying information of all
affected gas wells completed, electronic or hard copy photographs
documenting REC in progress for each well for which REC was required
and the self-certification required in the standard annual report. The
operator retains a digital image of each REC in progress. The image
must include a digital date stamp and geographic coordinates stamp to
help link the photograph with the specific well completion operation.
2. Standards for Compressor Affected Facilities
    The final rule requires measures to reduce VOC emissions from
centrifugal and reciprocating compressors. Compressors located at the
wellhead or in the transmission, storage and distribution segments are
not covered by this final rule and, therefore, are not affected
facilities. The final rule contains standards for wet seal centrifugal
compressors located in the natural gas production segment and the
natural gas processing segment up the point at which the gas enters the
transmission and storage segment. The final standards require 95.0
percent reduction of the emissions from each wet seal centrifugal
compressor affected facility. The standard can be achieved by capturing
and routing the emissions to a control device that achieves an emission
reduction of 95.0 percent.
    The operational standards for reciprocating compressors in the
final rule require replacement of the rod packing based on usage. The
owner or operator of a reciprocating compressor affected facility is
required to change the rod packing immediately when hours of operation
reach 26,000 hours (equivalent to 36 months of continuous usage).
Alternatively, owners or operators can elect to change the rod packing
every 36 months in lieu of monitoring compressor operating hours. An
owner or operator who elects to meet the 26,000 hour requirement is
required to monitor the duration (in hours) that the compressor is
operated, beginning on the date of initial startup of the reciprocating
compressor affected facility, or on the date of the previous rod
packing replacement, whichever is later.
3. Standards for Pneumatic Controller Affected Facilities
    We are also finalizing pneumatic controller VOC standards. The
affected facility is a continuous bleed, natural gas-driven pneumatic
controller with a natural gas bleed rate greater than 6 scfh for which
construction commenced after August 23, 2011, located (1) in the oil
production segment between the wellhead and the point of custody
transfer to an oil pipeline; or (2) in the natural gas production
segment, excluding natural gas processing plants, between the wellhead
and the point at which the gas enters the transmission and storage
segment. Except for controllers located at natural gas processing
plants, each continuous bleed, natural gas-driven pneumatic controller
that emits more than 6 scfh is an affected facility if it is
constructed or modified after August 23, 2011. Pneumatic controllers
with a bleed rate of 6 scfh or less in the oil and natural gas
production segment and all pneumatic controllers located in the natural
gas transmission, storage and distribution segments are not covered by
this final rule and, therefore, are not affected facilities. At natural
gas processing plants, the affected facility is each individual
continuous bleed natural gas-operated pneumatic controller, and the
final rule includes a natural gas bleed rate limit of zero scfh. The
final emission standards for pneumatic controllers at natural gas
processing plants reflect the emission level achievable from the use of
non-natural gas-driven pneumatic controllers. At other locations in the
oil and natural gas production segment, the final rule includes a
natural gas bleed rate limit of 6 standard cubic feet of gas per hour
for an individual pneumatic controller. The standards provide
exemptions in cases where it has been demonstrated that the use of a
natural gas-driven pneumatic controller with a bleed rate above the
applicable standard is required. However, as discussed in section IX.C,
the EPA is allowing a 1-year phase-in period for pneumatic controllers
in the final rule.
4. Standards for Storage Vessels
    The final rule contains VOC standards for new, modified or
reconstructed storage vessels located in the oil and natural gas
production, natural gas processing and natural gas transmission and
storage segments. The final rule, which applies to individual storage
vessels, requires that storage vessels with VOC emissions equal to or
greater than 6 tpy achieve at least 95.0 percent reduction in VOC
emissions. For storage vessels constructed, modified or reconstructed
at well sites with no wells already in production at the time of
construction, modification or reconstruction, the final rule provides a
30-day period from startup for the owner or operator to determine
whether the magnitude of VOC emissions from the storage vessel will be
at least 6 tpy. If the storage vessel requires control, the final rule
provides an additional 30 days for the control device to be installed
and operational. For storage vessels constructed, modified or
reconstructed at well sites with one or more wells already in
production at the time of construction, modification or reconstruction,
these estimation and installation periods are not provided because an
estimate of VOC emissions can be made using information on the liquid
production characteristics of the existing wells.
    In addition, the final rule provides for a 1-year phase-in period
for storage vessel controls. Refer to section IX.E.4 of this preamble
for further discussion.
5. Standards for Affected Facilities Located at Onshore Natural Gas
Processing Plants
    For onshore natural gas processing plants, we are revising the
existing NSPS requirements for LDAR to reflect the procedures and leak
thresholds established by 40 CFR part 60, subpart VVa. Subpart VVa
lowers the leak definition for valves from 10,000 ppm to 500 ppm, and
requires the monitoring of connectors. Pumps, pressure relief devices
and open-ended valves or lines are also monitored.
6. Standards for Sweetening Unit Affected Facilities at Onshore Natural
Gas Processing Plants
    The final rule regulates SO2 emissions from natural gas
processing plants by requiring affected facilities to reduce
SO2 emissions by recovering sulfur. The final rule
incorporates the provisions of 40 CFR part 60, subpart LLL into 40 CFR
part 60, subpart OOOO, and minor revisions were made to adapt the
subpart LLL language to subpart OOOO. The final rule also increased the
SO2 emission reduction standard from the subpart LLL
requirement of 99.8 percent to 99.9 percent for units with sulfur
production rate of at least 5 long tons per day. This change is based
on reanalysis of the original data used in the subpart LLL BSER
analysis.

B. What are the effective and compliance dates for the final NSPS?

    The revisions to the existing NSPS standards and the new NSPS
standards promulgated in this action are effective on October 15, 2012.
Affected facilities must be in compliance with the final standards on
the effective date, October 15, 2012.

V. Summary of the Significant Changes to the NSPS Since Proposal

    The previous section summarized the requirements that the EPA is
finalizing in this rule. This section will discuss in greater detail
the key changes the EPA has made since proposal. These changes result
from the EPA's review of the additional data and information provided
to us and our consideration of the many substantive and thoughtful
comments submitted on the proposal.
    We believe the changes make the final rule more flexible and cost-
effective, address concerns with equipment availability, streamline
recordkeeping and reporting requirements and improve clarity, while
fully preserving or improving the public health and environmental
protection required by the CAA.

A. Gas Well Affected Facilities

    We have revised the requirements for gas well affected facilities
since proposal in response to comment. The final rule applies to three
subcategories of fractured and refractured gas wells for which well
completion operations are conducted: (1) Wildcat (exploratory) and
delineation gas wells; (2) non-wildcat and non-delineation gas wells
for which the reservoir pressure is insufficient for a REC to be
performed, as determined by a simple calculation involving reservoir
pressure, well depth and flow line pressure at the sales meter (we
refer to these wells as ``low pressure gas wells''); and (3) other
fractured and refractured gas wells. In the proposed 40 CFR part 60,
subpart OOOO, upon promulgation of this rule, each well completion or
recompletion at a non-exploratory or non-delineation well would have
had to employ REC with combustion. Because of uncertainties in the
supply of equipment and labor over the near-term, we are now requiring
this work practice standard for completion operations begun at
subcategory (3) gas wells (non-exploratory and non-delineation wells)
on or after January 1, 2015. Until this date, flowback emissions must
either be controlled using REC or routed to a completion combustion
device unless it is technically infeasible or unsafe to do so. Owners
and operators are encouraged to use REC when available during this
period. Completion operations at subcategory (1) gas wells (wildcat and
delineation wells) and subcategory (2) gas wells (non-wildcat and non-
delineation low pressure gas wells) begun on or after October 15, 2012
are required to control flowback emissions by using REC with combustion
or by routing emissions to a completion combustion device alone unless
it is technically infeasible or unsafe to do so.
    The final rule includes a specific modification provision for well
completions in lieu of the General Provisions in 40 CFR 60.14. For a
more detailed explanation, please see section IX.A of this preamble. In
addition, we have revised the definition of ``flowback period'' to more
clearly define when the flowback period begins and ends.
    In the proposed rule, all completions at existing wells (i.e.,
those originally constructed on or before August 23, 2011) that are
subsequently fractured or refractured were considered to be
modifications. In the final rule, completions of wells that are
refractured on or after the rule's effective date are not considered
modified and, as a result, are not affected facilities under the NSPS,
if the completion operation is conducted with the use, immediately upon
flowback, of emission control techniques required on or after January
1, 2015, for new wells and satisfies other requirements, including
notification, recordkeeping and reporting requirements.
    In the proposed rule, we prescribed specific equipment to
accomplish an REC. In the final rule, we have removed the required
equipment specifications for REC and added operational standards that
will result in minimizing emissions and maximizing product recovery. In
light of the comments received, we conclude that it is inappropriate
and unnecessary to prohibit the use of other equipment that can be used
to accomplish an REC and that the operational standards can be achieved
using a variety of equipment that can change from well to well.
    Initial compliance requirements for gas well affected facilities
have also been revised and streamlined. Owners and operators are now
required to notify the Administrator of the actual date of each well
completion operation by email no later than 2 days prior to the well
completion operation, rather than the proposed requirement of notifying
the Administrator of the date of the well completion operation within
30 days of the commencement of each well completion operation. The
email must include information that had been part of the 30-day advance
notification, as described in the proposed rule, including contact
information for the owner and operator, well identification, geographic
coordinates of the well and planned date of the beginning of flowback.
However, if the owner or operator is subject to state regulations that
require advance notification of well completions and has met those
advance notification requirements, then the owner or operator is
considered to have met the advance notification requirements for gas
well completions under the NSPS.
    In the final rule, the recordkeeping and reporting requirements for
well completions also provide for a streamlining option that owners and
operators may choose in lieu of the standard annual reporting
requirements. The standard annual report must include copies of all
well completion records for each gas well affected facility for which a
completion operation was performed during the reporting period. The
alternative, streamlined annual report for gas well affected facilities
requires submission of a list, with identifying information of all
affected gas wells completed, electronic or hard copy photographs
documenting REC in progress for each well for which REC was required
and the self-certification required in the standard annual report. The
operator retains a digital image of each REC in progress. The image
must include a digital date stamp and geographic coordinates stamp to
help link the photograph with the specific well completion operation.
    Refer to section IX.B of this preamble and the Responses to
Comments document, available in the docket, for detailed discussion
regarding these changes.

B. Centrifugal and Reciprocating Compressor Affected Facilities

    In the final rule, we have made changes that impact both
reciprocating and centrifugal compressor affected facilities in
response to comments requesting clarification. Because we are not
finalizing standards covering them, centrifugal and reciprocating
compressors located in the transmission, storage and distribution
segments are not affected facilities.
    In the proposed rule, all centrifugal compressors would be required
to use dry seals. We had also solicited comment on the use of wet seals
with controls as an acceptable alternative to dry seals due to
potential technical infeasibility of using dry seals for certain
applications. Based on comments received, the final rule requires that
centrifugal compressors with wet seals reduce emissions by 95.0

percent. The standard can be achieved by capturing and routing
emissions from the wet seal fluid degassing system to a control device
that reduces VOC emissions by 95.0 percent. Testing, monitoring,
recordkeeping, reporting and notification requirements associated with
the control devices have also been added. In contrast to the proposed
rule, in the final rule, centrifugal compressors with dry seals are not
affected facilities. More detailed discussion of this change is
presented in section IX.D of this preamble.
    As proposed, owners or operators of reciprocating compressor
affected facilities were required to change rod packing after 26,000
hours of operation. This is equivalent to approximately 36 months of
continuous operation. Based on comments we received, we are changing
the final rule to provide operators the option of changing the rod
packing every 36 months instead of tracking compressor hours of
operation and changing rod packing after 26,000 hours of operation.
    Refer to section IX.D of this preamble and the Responses to
Comments document, available in the docket, for detailed discussion
regarding these changes.

C. Pneumatic Controller Affected Facilities

    For pneumatic controller affected facilities located in the oil and
natural gas production segments, we have revised the definition of
pneumatic controller affected facility from a single pneumatic
controller to a single, continuous bleed, natural gas-driven pneumatic
controller with a continuous bleed rate greater than 6 scfh for which
construction, modification or reconstruction commenced after August 23,
2011. At natural gas processing plants, individual continuous bleed
natural gas-operated pneumatic controllers for which construction,
modification or reconstruction commenced after August 23, 2011, are
affected facilities under this rule. As explained further in section
IX.C of this preamble, this change provides clarity by more
specifically defining the pneumatic controllers we intended to regulate
in this final rule. In addition, only pneumatic controllers located
prior to the point at which the gas enters the transmission and storage
segment are subject to the NSPS. Because we are not finalizing
standards covering them, controllers located in the transmission and
storage segment are not affected facilities. The emission rates we
proposed for pneumatic controllers have not changed in the final rule.
    All new pneumatic controller affected facilities are required, in
the final rule, to be tagged with the month and year of installation
and identification that allows traceability to the records for that
controller.
    In the proposed rule, each pneumatic controller affected facility
would have to comply upon promulgation. The final rule allows a 1-year
phase-in beginning October 15, 2012 before the bleed rate limit is
effective for an affected facility. We believe this is necessary for at
least two reasons. First, owners and operators would demonstrate
compliance based on information in the manufacturers' specification. We
have concluded that such information is not always included in current
manufacturers' specifications and a period of time is required for
manufacturers to test their products and modify specifications to
include the information. Second, we are not aware of any add-on control
device that is or can be used to reduce VOC emissions from gas-driven
pneumatic devices.
    Finally, language in the proposed rule could have been interpreted
to mean that all pneumatic controllers installed in any year after the
proposal date must be reported each year, rather than those installed
only during the reporting period. In order to clarify and streamline
the recordkeeping and reporting requirements associated with pneumatic
controllers, we are requiring only information concerning those
affected facilities constructed, modified or reconstructed during the
reporting period to be included in the annual report.
    Refer to section IX.C of this preamble and the Responses to
Comments document, available in the docket, for detailed discussion
regarding these changes.

D. Storage Vessel Affected Facilities

    We have modified the definition of ``storage vessel'' to exclude
surge control vessels, knockout vessels and pressure vessels designed
to operate without emissions to the atmosphere. In addition, we have
clarified that we consider a storage vessel that is skid-mounted or
permanently attached to something that is mobile (such as trucks,
railcars, barges or ships) to be subject to 40 CFR part 60, subpart
OOOO if it is intended to be located at a site for at least 180
consecutive days.
    In the proposed rule, we established a throughput threshold for
storage vessels below which they were not subject to the NSPS. In order
to remove confusion with respect to the emission factors used to
develop the throughput threshold and to address comments indicating
significant difficulty measuring throughput, we have revised the final
rule such that storage vessels that emit 6 tpy of VOC or more are
subject to the NSPS, based on our analysis in the proposed rule showing
that the proposed NSPS is cost-effective for storage vessels with that
level of VOC emissions. In the final rule, for storage vessels
constructed, modified or reconstructed at well sites with no wells
already in production at the time of construction, the final rule
provides a 30-day period for the owner or operator to determine whether
the magnitude of VOC emissions from the storage vessel will be at least
6 tpy. If the storage vessel requires control, the final rule provides
an additional 30 days for the control device to be installed and
operational. For storage vessels constructed, modified or reconstructed
at well sites with one or more wells already in production at the time
of construction, modification or reconstruction, VOC emissions can be
determined prior to startup. Accordingly, these estimation and
installation periods are not necessary and, therefore, not provided.
    Several requirements for storage vessels in the proposed rule
pointed to 40 CFR part 63, subpart HH (the Oil and Natural Gas
Production NESHAP). However, subpart HH regulates HAP while this NSPS
regulates VOC. Therefore, in order to eliminate confusion caused by
cross-referencing another regulation and to tailor the requirements for
VOC regulation, we have incorporated the storage vessel requirements
from subpart HH into 40 CFR part 60, subpart OOOO and modified those
requirements, as appropriate for this rule.
    In the proposed rule, each storage vessel required to reduce
emissions would have to comply upon promulgation. In the final rule,
owners or operators are allowed a 1-year phase-in beginning October 15,
2012 before the 95.0-percent control requirement is effective. We
believe this is necessary because of initial problems securing control
devices that are manufacturer-tested and have appropriate documentation
for determining control efficiency. In addition, we believe that owners
or operators will require a period of time to establish the need for
controls and install them where called for. The 1-year phase-in will
also allow owners or operators the necessary time to establish the need
for a control device and procure and install the equipment.
    Refer to section IX.E of this preamble and the Responses to
Comments document, available in the docket, for detailed discussion
regarding these changes.

E. Equipment Leaks Affected Facilities and Sweetening Unit Affected
Facilities at Onshore Natural Gas Processing Plants
    We have revised the identification of affected facilities for
equipment leaks at natural gas processing plants. We proposed that
compressors and equipment (as defined in the rule) located at onshore
natural gas processing plants were affected facilities. As discussed
above, compressors (reciprocating and centrifugal) have requirements
under 40 CFR part 60, subpart OOOO that extend beyond the natural gas
processing plant. To remove the duplicative requirements for
compressors at natural gas processing plants, we have revised the
identification of affected facility to exclude compressors from the
standards that apply to equipment leaks at onshore natural gas
processing plants. Refer to the Responses to Comments document,
available in the docket, for detailed discussion regarding these
affected facilities.

F. Changes to Notification, Recordkeeping and Reporting Requirements

    In response to comment expressing concern with the burdens
associated with demonstrating and monitoring compliance, we have
reanalyzed the notification, recordkeeping and reporting requirements
in the proposed rule and eliminated duplicative and unnecessary
requirements for all emission points. For well completions,
compressors, pneumatic controllers and storage vessels, we have removed
the General Provisions notification requirements in 40 CFR 60.7(a)(1),
(3) and (4). These requirements relate to notification of construction
and initial performance testing and are more suited to construction of
more traditional facilities (e.g., gas processing plants, refineries
and chemical plants) than the numerous individual pieces of apparatus
(e.g., individual pneumatic controllers, compressor and storage
vessels) that are ``affected facilities'' under this final rule.
Specific notification and initial compliance demonstration requirements
in the final rule make the General Provisions notification requirements
unnecessary for gas well affected facilities.
    As mentioned previously, we have also streamlined the notification,
recordkeeping and reporting requirements for gas well affected
facilities. In place of a written notification of each well completion
operation 30 days prior to the completion, owners or operators must
submit a notification no later than 2 days prior to the date of the
completion. This notification may be submitted by email. To avoid
duplicative and potentially conflicting advance notification
requirements, the final rule provides that owners or operators who are
subject to state regulations that require advance notification of well
completions and have met those notification requirements are considered
to have met the advance notification requirements of the NSPS.
Additionally, in lieu of the standard annual reporting requirements,
the final rule allows submission of an annual report for gas well
affected facilities that consists only of a list, with identifying
information of all affected gas wells completed, electronic or hard
copy photographs documenting REC in progress for each well for which
REC was required and the self-certification required in the standard
annual report.
    In the affirmative defense provisions of the rule, a citation was
corrected, minor wording changes were made and reporting requirements
were refined. The provisions we retained in the final rule are those we
believe are necessary to assure regulatory agencies and the public that
the owner or operator is in compliance with the final rule. Refer to
section IX.F of this preamble and the Responses to Comments document,
available in the docket, for detailed discussion regarding these
changes.

VI. Summary of the Final NESHAP Rules

A. What are the final rule actions relative to the Oil and Natural Gas
Production (subpart HH) source category?

    Table 4 summarizes the changes to 40 CFR part 63, subpart HH.
Further discussion of these changes may be found below in this section
and in sections VII and X of this preamble.

        Table 4--Summary of Changes to 40 CFR Part 63, Subpart HH
------------------------------------------------------------------------
       Affected source          Nature of change          Standard
------------------------------------------------------------------------
Small glycol dehydrators....  Established MACT      BTEX emission limit:
                               standards for        New sources--4.66 x
                               previously            10-6 g/scm-ppmv.
                               unregulated source.  Existing sources--
                                                     3.28 x 10-4 g/scm-
                                                     ppmv.
``Associated equipment''....  Revised definition    N/A.
                               to exclude all
                               storage vessels.
Valves--equipment leaks.....  Revised definition    LDAR for valves must
                               of leak.              be applied at 500
                                                     ppm.
All affected sources........  Eliminated exemption  Standards apply at
                               from compliance       all times.
                               during periods of
                               startup, shutdown
                               and malfunction.
------------------------------------------------------------------------

    Pursuant to CAA sections 112(d)(2) and (3), we have established
MACT standards for small glycol dehydrators that were not regulated in
the initial NESHAP. In addition, we have revised the definition of
``associated equipment'' to exclude from the definition of that term
all storage vessels, not just those with potential for flash emissions
(PFE).
    With regard to our CAA section 112(d)(6) review, we conclude that
there have been no developments in practices, processes or control
technologies for large glycol dehydrators and storage vessels with PFE.
As noted at proposal, however, there have been relevant developments
for equipment leaks, and we are finalizing the proposed revisions to
the leak definition for valves at natural gas processing plants.
Specifically, under CAA section 112(d)(6), we revised the leak
definition for valves to 500 ppm, thus requiring the application of the
leak detection and repair requirement at this lower detection level. We
did not make other revisions to the standards pursuant to our CAA
section 112(d)(6) review. Our review under CAA section 112(f)(2) also
did not result in revision to the standards. We found that the MACT
standards in 40 CFR part 63, subpart HH (coupled with the new MACT
standard for small glycol dehydrators) provide an ample margin of
safety to protect public health and prevent adverse environmental
effects. Accordingly, we are re-adopting those standards to satisfy the
requirements of CAA section 112(f).
    Additionally, we amended 40 CFR part 63, subpart HH to apply the
standards at all times and made other revisions relative to periods of
startup,

shutdown and malfunction. Lastly, the final rule revises and adds
certain testing and monitoring and related notification, recordkeeping
and reporting requirements and makes certain other minor technical
revisions to the NESHAP.
1. Standards for Small Glycol Dehydration Units
    In this final rule, we have established MACT standards under CAA
sections 112(d)(2) and (3) for small glycol dehydration units, which
were left unregulated in the initial NESHAP. This 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). The final MACT standards for small dehydrators at oil and gas
production facilities require that existing affected sources at a major
source meet a unit-specific BTEX limit of 3.28 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.
2. Standards for Equipment Leaks
    In the final rule, as a result of our technology review under CAA
section 112(d)(6), we are revising the leak definition for valves to
500 ppm, thus requiring the application of the LDAR requirement at this
lower detection level. This leak definition applies only to valves at
natural gas processing plants, and not other components.
3. Notification, Recordkeeping and Reporting Requirements
    The final rule revises certain recordkeeping requirements of 40 CFR
part 63, subpart HH. Specifically, facilities using carbon adsorbers as
a control device are required to 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 of operation (i.e., process
equipment) or the air pollution control equipment and monitoring
equipment.
    In conjunction with the new MACT standards for small existing
glycol dehydration units, owners and operators of such affected units
are required to submit an initial notification within 1 year after they
become subject to the provisions of this subpart or by October 15,
2013, whichever is later.
    The final amendments to the NESHAP also include additional
requirements for the contents of the periodic reports. The periodic
reports are required to include periodic test results and information
regarding any carbon replacement events that occurred during the
reporting period. Additionally, periodic reports are required to
include the number, duration, and a brief description for each type of
malfunction which occurred during the reporting period and which caused
or may have caused any applicable emission limitation to be exceeded.
The periodic report is also required to include a description of
actions taken by an owner or operator during a malfunction of an
affected source to minimize emissions, including actions taken to
correct a malfunction.

B. What are the final rule amendments for the Natural Gas Transmission
and Storage (subpart HHH) source category?

    Table 5 summarizes the changes to 40 CFR part 63, subpart HHH.
Further discussion of these changes may be found below in this section
and in sections VII and X of this preamble.

       Table 5--Summary of Changes to 40 CFR Part 63, Subpart HHH
------------------------------------------------------------------------
       Affected source          Nature of change          Standard
------------------------------------------------------------------------
Small glycol dehydrators....  Established MACT      BTEX emission limit:
                               standards for        New sources--5.44 x
                               previously            10-5 g/scm-ppmv.
                               unregulated source.  Existing sources--
                                                     3.01 x 10-4 g/scm-
                                                     ppmv.
All affected sources........  Eliminated exemption  Standards apply at
                               from compliance       all times.
                               during periods of
                               startup, shutdown
                               and malfunction.
------------------------------------------------------------------------

     Pursuant to CAA section 112(d)(2) and (3), we have established
MACT standards for small glycol dehydrators that were not regulated in
the initial NESHAP. We have also amended 40 CFR part 63, subpart HHH to
apply the standards at all times, and made other revisions relative to
periods of startup, shutdown and malfunction. Lastly, the final rule
revises and adds certain testing and monitoring and related
notification, recordkeeping and reporting requirements, as well as
makes other minor technical revisions to the NESHAP.
    With regard to our CAA section 112(d)(6) review, we conclude that
there have been no developments in practices processes or control
technologies for large glycol dehydrators. We also found that the MACT
standards in 40 CFR part 63, subpart HHH (coupled with the new MACT
standard for small glycol dehydrators) provide an ample margin of
safety to protect public health and prevent adverse environmental
effects. Accordingly, we are re-adopting those standards to satisfy the
requirements of CAA section 112(f). Thus, our reviews under CAA
sections 112(d)(6) and 112(f)(2) did not result in any revisions to the
standards.
1. Standards for Glycol Dehydration Units
    In this final rule, we have established MACT standards for small
glycol dehydration units in the Natural Gas Transmission and Storage
source category. This 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 final MACT
standard for this subcategory of small dehydrators requires existing
affected sources to meet a unit-specific BTEX emission limit of 3.01 x
10-4 grams BTEX/scm-ppmv and new affected sources are
required to meet a BTEX limit of 5.44 x 10-5 grams BTEX/scm-
ppmv.
2. Notification, Recordkeeping and Reporting Requirements
    The final rule revises certain recordkeeping requirements of 40 CFR
part 63, subpart HHH. Specifically, facilities using carbon adsorbers
as a control device are required to 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 of operation (i.e., process
equipment) or the air pollution control equipment and monitoring
equipment.
    In conjunction with the promulgation of the MACT standards for
small glycol dehydration units, the final rule requires that owners and
operators of such affected units submit an initial notification within
1 year after the unit becomes subject to the provisions of this

subpart or by October 15, 2013, whichever is later.
    The final amendments to the NESHAP also include additional
requirements for the contents of the periodic reports. For 40 CFR part
63, subpart HHH, the periodic reports are required to include periodic
test results and information regarding any carbon replacement events
that occurred during the reporting period. Additionally, periodic
reports are required to include the number, duration, and a brief
description for each type of malfunction which occurred during the
reporting period and which caused or may have caused any applicable
emission limitation to be exceeded. The periodic report is also
required to include a description of actions taken by an owner or
operator during a malfunction of an affected source to minimize
emissions, including actions taken to correct a malfunction.

C. What is the effective date of this final rule and compliance dates
for the standards?

    The effective date of this rule is October 15, 2012.
    The compliance date for new affected sources (those that commenced
construction or reconstruction on or after August 23, 2011) is
immediately upon initial startup or the effective date of the
standards, October 15, 2012, whichever is later.
    The compliance date for existing small glycol dehydration units
that are subject to MACT for the first time (i.e., those that commenced
construction before August 23, 2011) is October 15, 2015.
    An affected source at a production field facility that constructed
before August 23, 2011, that was previously determined to be an area
source but becomes a major source on October 15, 2012 due to the
amendment to the associated equipment definition in 40 CFR part 63,
subpart HH, has until October 15, 2015 to comply with the relevant
emission standards.
    The compliance date for valves at existing natural gas processing
plants, constructed before August 23, 2011, due to the amendment to the
leak definition in 40 CFR part 63, subpart HH, is 1 year after the
effective date of the standards October 15, 2013.

VII. Summary of the Significant Changes to the NESHAP Since Proposal

    The previous section described the requirements that the EPA is
finalizing in this rule. This section discusses in greater detail the
key changes the EPA is making from the proposal. These changes result
from the EPA's review of the additional data and information provided
to us and our consideration of the substantive comments submitted on
the proposal.
    We have retained the same approach and methodology to establishing
the standards as described at proposal. We have, however, made some
changes in response to comments, which are described further below. One
change resulted in revisions to the MACT emission limits for small
glycol dehydration units. In addition, based on the comments received,
we are not finalizing the MACT standard for the subcategory of storage
vessels without the PFE, which was a subcategory that was left
unregulated in the 1999 40 CFR part 63, subpart HH rule. Specifically,
based on our review of the comments, we believe that we need additional
data and information to set an emission standard for storage vessels
without the PFE, and we intend to collect the additional data and
propose MACT emission standards under section 112(d)(2) and (3) of the
CAA for such storage vessels. Finally, we are retaining the 0.9 Mg/yr
compliance option for large dehydration units.

A. What are the significant changes since proposal for the Oil and
Natural Gas Production (subpart HH) source category?

1. Changes Made to Amendments Proposed Under the Authority of CAA
Sections 112(d)(2) and (3)
    Under the authority of sections 112(d)(2) and (3) of the CAA, we
proposed amendments to 40 CFR part 63, subpart HH by adding
requirements for previously unregulated units; specifically, we
proposed standards for small glycol dehydration units and storage
vessels without the PFE.
    In the final amendments for 40 CFR part 63, subpart HH, we have
revised the proposed MACT standards for small glycol dehydration units
in response to comments that we did not take into account variability
in the development of the MACT floor. In our proposal, the MACT
standards for existing affected sources was a unit-specific BTEX limit
of 1.10 x 10-4 g BTEX/scm-ppmv and for new affected sources
was a BTEX limit of 4.66 x 10-6 g BTEX/scm-ppmv. In this
final rule, we accounted for variability by using an upper prediction
limit to develop a revised BTEX emission limit for existing small
glycol dehydration units of 3.28 x 10-4 grams BTEX/standard
cubic meters (scm)-parts per million by volume (ppmv) and for new small
glycol dehydration units the revised BTEX limit is 4.66 x
10-6 grams BTEX/scm-ppmv. The process for developing these
emissions limitations is documented in the Response to Comments
document and a technical memorandum, both of which are in the docket.
    Finally, as noted above, in response to comments, we are not
finalizing MACT standards for storage vessels without the PFE in this
rule. We received numerous comments expressing concerns with how we
established the proposed standards for this subcategory. In response to
such comments, we have re-evaluated the proposed MACT standards and
concluded that we need (and intend to gather) additional data on these
sources in order to analyze and establish MACT emission standards for
this subcategory of storage vessels under section 112(d)(2) and (3) of
the CAA. See the Response to Comments document for additional
discussion.
2. Changes Made to Amendments Proposed Under the Authority of CAA
Section 112(f)(2)
    We proposed to eliminate the 0.9 Mg/yr benzene compliance option
for large glycol dehydration units because, in the proposed rule, we
estimated that the emissions allowed as the result of this compliance
option resulted in estimated cancer risks up to 400-in-1-million. We
received multiple comments concerning our proposed risk estimate. After
reviewing these comments, we discovered that we had significantly
overestimated the allowable emissions associated with this compliance
option. First, for several sources, including the source that we
predicted had the 400-in-1 million MIR, we used an incorrect factor (or
multiplier) to scale up actual emissions associated with sources that
could utilize the compliance option level of 0.9 Mg/yr to allowables.
We used an incorrect factor due to an inadvertent transcription error
in our calculations. Second, we learned that the risk assessment
supporting the proposed rule erroneously included several area sources,
which are not subject to 40 CFR part 63, subpart HH and thus should not
have been included in the CAA section 112(f) risk assessment. After
revising the risk assessment to remove area sources, and considering
the MACT standard promulgated today for small glycol dehydrators
pursuant to CAA sections 112(d)(2) and (3), the MIR for the Oil and
Natural Gas Production source category based on actual and allowable
emissions is 10-in-1 million, compared to the 400-in-1 million\3\ based
on

allowable emissions and 40-in-1 million based on actual emissions that
were estimated in the proposed rule.
---------------------------------------------------------------------------

    \3\ At proposal, we used an incorrect factor (or multiplier) in
calculating allowable emissions for the source that, at proposal,
had an estimated MIR of 400-in-1 million. Since proposal, we have
learned that this source is an area source and thus is not subject
to the Subpart HH MACT standards. As such, we removed this source
from our section 112(f) risk analysis. In any event, we have
determined that even if this area source were to have actual
emissions at the 0.9 Mg/yr level, its risk would be 3-in-1 million.
---------------------------------------------------------------------------

    As the result of our revised risk analysis, we have determined that
approximately 120,000 people are estimated to have cancer risks at or
above 1-in-1 million, compared to 160,000 people estimated in the
proposed rule. Total estimated cancer incidence from the source
category is 0.02 excess cancer cases per year, or one case in every 50
years. This estimate is unchanged from the proposed rule because the
incidence from a small number of sources typically does not affect
total incidence reported to one significant figure. The estimate from
the proposed rule of maximum chronic non-cancer TOSHI value (0.1) is
unchanged, driven by naphthalene emissions from fugitive sources. The
maximum acute non-cancer hazard quotient value (9, based on the
California EPA reference exposure level (REL) for benzene) is also
unchanged from the proposed rule. Although driven by the same pollutant
that drives the MIR, benzene, the maximum acute hazard quotient value
did not change from the proposed rule because the source driving the
acute value was not identified as an area source and, thus, remained in
the revised analysis. It is common for the maximum acute hazard
quotient and cancer MIR not to coincide because the acute value is
strongly dependent on short-term meteorology and the distance to the
facility property boundary, whereas the MIR is dependent on long-term
meteorology and the distance to census block receptors. There are 13
cases in the source category (out of approximately 1,000 facilities)
where the REL is exceeded by more than a factor of 2.
    Based on the conservative nature of the acute exposure scenario
used in the screening assessment for this source category, the EPA has
judged that, considering all associated uncertainties, the potential
for effects from acute exposures is low. Screening estimates of acute
exposures were evaluated for each HAP at the point of highest off-site
exposure for each facility (i.e., not just the census block centroids)
assuming that a person is present at this location at a time when both
the peak emission rate and worst-case dispersion conditions occur.
Although the REL (which indicates the level below which adverse effects
are not anticipated) is exceeded in this case, we believe the potential
for acute effects is low for several reasons. The acute modeling
scenario is worst-case because of the confluence of peak emission rates
and worst-case dispersion conditions. Also, the generally sparse
populations near the facilities with the highest estimated 1-hour
exposures make it less likely that a person would be near the plant to
be exposed.
    We also conducted a facility-wide risk assessment. The maximum
facility-wide risk estimate of 100-in-1 million is unchanged from the
proposed rule. Also unchanged from proposal is the fact that the
facility-wide risk is driven by emissions from reciprocating internal
combustion engines (RICE) and these engines are not part of the Oil and
Natural Gas Production source category. In fact, oil and natural gas
production operations contribute only about one percent or less to the
total facility-wide risks. In the last few years, the Agency has
revised the MACT standards for certain RICE. See 75 FR 9648 and 51570.
Although it is difficult to discern from the available data which types
of RICE are driving the facility-wide risk, it is important to note
that the 2005 National Emissions Inventory (NEI) data on which we
modeled risk did not take into account the recent MACT revisions to the
RICE rule. Finally, our assessment that the potential for significant
human health risks due to multipathway exposures or adverse
environmental effects is low has not changed since proposal (see 76 FR
52774).
    Consistent with the approach established in the Benzene NESHAP, the
EPA weighed all health risk measures and information, including the
maximum individual cancer risk, the cancer incidence, the number of
people exposed to a risk greater than 1-in-1-million, the distribution
of risks in the exposed population, and the uncertainty of our risk
calculations in determining whether the risk posed by emissions from
Oil and Natural Gas Production is acceptable. In this case, because the
MIR is well below 100-in-1-million, and because a number of other
factors indicate relatively low risk concern, including low cancer
incidence, low potential for adverse environmental effects or human
health multi-pathway, and unlikely chronic and acute noncancer health
impacts, we conclude that the level of risk associated with the Oil and
Natural Gas Production source category MACT standards (including the
small glycol dehydrator MACT standard issued here) is acceptable.\4\
---------------------------------------------------------------------------

    \4\ We reach the same conclusion even if we do not consider the
new MACT for small glycol dehydrators in our acceptability
determination. Indeed, focusing solely on the standards in the
existing MACT, the level of risk associated with such standards
would remain 10-in-1 million, and thus our acceptability
determination does not change. There is one facility that is a small
glycol dehydrator that has an MIR of 10-in-1 million. After
imposition of the MACT for small glycol dehydrators, however, this
unit would have an MIR of 7-in-1 million. Also, see memorandum
titled Supplemental Facility Information Obtained from Various
State/Local Agencies and Additional Analysis, March 20, 2012.
---------------------------------------------------------------------------

    In making our proposed ample margin of safety determination under
CAA section 112(f)(2), we subsequently evaluated the risk reductions
and costs associated with various emissions control options to
determine whether we should impose additional standards to reduce risks
further. As stated above, we made certain revisions to the risk
assessment in response to comments and the resulting MIR for 40 CFR
part 63, subpart HH is 10-in-1 million. We have not identified any
emission control options that would reduce emissions and risk
associated with subpart HH sources for glycol dehydration units and
storage vessels. Our proposed amendment to remove the 0.9 Mg/yr
compliance option does not affect the risk driver, which is fugitive
emissions. As a result, we are retaining the 0.9 Mg/yr compliance
option in the final rule. We have determined that the risks associated
with the level of emissions allowed by the MACT standards are driven by
fugitive emissions (i.e., leaks).
    Since a LDAR program is the typical method for reducing emissions
from fugitive sources, we considered requiring a LDAR program to reduce
risk for this source category. The NEI dataset for this source category
contains approximately 2,500 emission points that we characterized as
fugitive. These emission points are located at 639 facilities. The
fugitive emissions associated with those 639 facilities are 747 tons of
HAP.
    In evaluating the effectiveness of a LDAR program at these
facilities we looked at two different LDAR programs--one is a program
equivalent to 40 CFR part 60, subpart VV, and the second is a more
stringent program equivalent to 40 CFR part 60, subpart VVa.\5\ A LDAR
program equivalent to subpart VV can achieve emission reductions of
approximately 39 percent with capital and annual costs of

$237,700 and $79,419 per facility, respectively. Therefore, such a
program for the 639 facilities would be expected to reduce emissions by
249 tons of HAP with total capital and annual costs of $152 million and
$50.7 million, respectively. The cost effectiveness would be
approximately $204,000 per ton of HAP.
---------------------------------------------------------------------------

    \5\ See memorandum titled Equipment Leak Emission Reduction and
Cost Analysis for Well Pads, Gathering and Boosting Stations, and
Transmission and Storage Facilities Using Emission and Cost Data
from the Uniform Standards, April 17, 2012.
---------------------------------------------------------------------------

    A LDAR program equivalent to 40 CFR part 60, subpart VVa can
achieve emission reductions of approximately 43 percent overall with
capital and annual costs of $241,000 and $82,900 per facility,
respectively. Therefore, an LDAR program for the 639 facilities would
be expected to reduce emissions by 275 tons of HAP, with total capital
and annual costs of $154 million and $53 million, respectively. The
cost effectiveness would be approximately $193,000 per ton of HAP
reduced. These additional control requirements would reduce the MIR for
the source category from 10-in-1 million to approximately 7-in-1
million.
    As explained in the proposal, in accordance with the approach
established in the Benzene NESHAP, we weigh all health risk measures
and information considered in the risk acceptability determination,
along with the costs and economic impacts of emissions controls,
technological feasibility, uncertainties and other relevant factors, in
making our ample margin of safety determination and deciding whether
standards are necessary to reduce risks further. Considering all of
this information, we conclude that the costs of the options analyzed
are not reasonable considering the emissions reductions and risk
reductions potentially achievable with the control measures evaluated.
Thus, we conclude that the MACT standards in 40 CFR part 63, subpart HH
(coupled with the new MACT standard for small glycol dehydrators)
provide an ample margin of safety to protect public health and prevent
adverse environmental effects. Accordingly, we are re-adopting those
standards to satisfy the requirements of CAA section 112(f).
3. Changes Made to Standards Proposed Under the Authority of CAA
Section 112(d)(6)
    As discussed in detail in the preamble for the proposed rule (76 FR
52784), we conducted a technology review for glycol dehydration units,
storage vessels and equipment leaks under the authority of CAA section
112(d)(6). We assessed developments in practices, processes and control
technologies sources for those regulated under the initial NESHAP and
determined that it was cost-effective to lower the leak definition for
valves at natural gas processing plants. We did not identify
developments in practices, processes and control technologies for
glycol dehydration units and storage vessels. As a result of this
assessment, we proposed revisions to the equipment leak requirements in
40 CFR part 63, subpart HH to lower the leak definition for valves to
an instrument reading of at least 500 ppm. No significant changes since
proposal were made to the equipment leak standards proposed under the
authority of section 112(d)(6) of the CAA.\6\
---------------------------------------------------------------------------

    \6\ Memorandum from Brown, Heather, EC/R Inc., to Moore, Bruce,
U.S. EPA, titled Technology Review for the Final Amendments to
Standards for the Oil and Natural Gas Production and Natural Gas
Transmission and Storage Source Categories.
---------------------------------------------------------------------------

4. Other Changes to the Proposed Rule
    We are revising the emission reduction demonstrated using the
manufacturers performance test from 98.0 percent to 95.0 percent.
Specifically, if an owner or operator chooses to install a combustion
control device that is tested under, and passes, the prescribed
manufacturers performance test the final rule states that the control
device has demonstrated a destruction efficiency of 95.0 percent. This
change is a result of comments and data provided on the actual
performance of these devices in the field.
    In the proposed rule, we proposed that the standards apply at all
times and removed provisions that provided an exemption from the
emission standards during SSM. In response to comments that the
monitoring and reporting provisions related to excursions occurring
during SSM events that remain in the subpart suggest exemption and
therefore should be removed, we are removing these provisions in the
final rule.
    Refer to the Reponses to Comments document, available in the
docket, for detailed discussion regarding these changes.

B. What are the significant changes since proposal for the Natural Gas
Transmission and Storage (subpart HHH) source category?

1. Changes Made to Amendments Proposed Under the Authority of CAA
Sections 112(d)(2) and (3)
    Under the authority of sections 112(d)(2) and (3) of the CAA, we
proposed amendments to 40 CFR part 63, subpart HHH by adding
requirements for previously unregulated units; specifically, we
proposed standards for small glycol dehydration units.
    In the final amendments for 40 CFR part 63, subpart HHH, we have
revised the proposed BTEX limits for small glycol dehydration units in
response to comments that we did not take into account variability in
the development of the MACT floor. We had proposed a unit-specific BTEX
emission limit of 6.42 x 10-5 grams BTEX/scm-ppmv for
existing sources and a BTEX limit of 1.10 x 10-5 g BTEX/scm-
ppmv for new sources. In the final rule, we accounted for variability
by using an upper prediction limit to develop a revised emission limit
for existing affected sources of 3.10 x 10-4 g BTEX/scm-ppmv
and for new affected sources is a BTEX limit of 5.44 x 10-5
grams BTEX/scm-ppmv. The process for developing these emissions
limitations is documented in the response to comments document and a
technical memorandum both of which can be found in the docket.
2. Changes to Amendments Proposed Under the Authority of CAA Section
112(f)(2)
    We proposed to eliminate the 0.9 Mg/yr benzene compliance option
for large glycol dehydration unit process vents because, in the
proposed rule, we estimated that the emissions allowed as the result of
this compliance option resulted in estimated cancer risks up to 90-in-
1-million. In response to comments, we learned that the risk assessment
supporting the proposed rule erroneously included some sources that
have permanently shut down, and several area sources, which are not
subject to 40 CFR part 63, subpart HHH and, thus, should not have been
included in the CAA section 112(f) risk assessment. After revising the
risk assessment to remove these sources and considering the MACT
standards promulgated here pursuant to CAA section 112(d)(2) and (3),
the MIR for the Natural Gas Transmission and Storage source category
based on actual and allowable emissions is 20-in-1 million, compared to
the 90-in-1 million based on allowable emissions and 20-in-1 million
based on actual emissions estimated in the proposed rule.
    As the result of our revised risk analysis, we have determined that
approximately 1,100 people are estimated to have cancer risks at or
above 1-in-1 million, compared to 2,500 people estimated in the
proposed rule. Total estimated cancer incidence from the source
category is 0.001 excess cancer cases per year, or one case in every
1,000 years. This estimate is unchanged from the proposed rule

because the incidence from a small number of sources typically does not
affect total incidence reported to one significant figure. The estimate
from the proposed rule of maximum chronic non-cancer TOSHI value (0.2)
is unchanged, driven by benzene emissions from fugitive sources. The
maximum acute non-cancer hazard quotient value (4, based on the benzene
REL) changed from the proposed rule; the value in the proposed rule was
5, but was associated with an area source that was removed from the
risk assessment. There are two cases in the source category (out of
approximately 300 facilities) where the REL is exceeded by more than a
factor of 2.
    Based on the conservative nature of the acute exposure scenario
used in the screening assessment for this source category, the EPA has
judged that, considering all associated uncertainties, the potential
for effects from acute exposures is low. Screening estimates of acute
exposures were evaluated for each HAP at the point of highest off-site
exposure for each facility (i.e., not just the census block centroids)
assuming that a person is present at this location at a time when both
the peak emission rate and worst-case dispersion conditions occur.
Although the REL (which indicates the level below which adverse effects
are not anticipated) is exceeded in this case, we believe the potential
for acute effects is low for several reasons. The acute modeling
scenario is worst-case because of the confluence of peak emission rates
and worst-case dispersion conditions. Also, the generally sparse
populations near the facilities with the highest estimated 1-hour
exposures make it less likely that a person would be near the plant to
be exposed.
    We also conducted a facility-wide risk assessment. The maximum
facility-wide risk estimate of 200-in-1 million is unchanged from the
proposed rule. Also unchanged from proposal is the fact that the
facility-wide risk is driven by emissions from reciprocating internal
combustion engines (RICE) and these engines are not part of the Natural
Gas Transmission and Storage source category. In fact, natural gas
transmission and storage operations contribute only about one percent
or less to the total facility-wide risks. In the last few years, the
Agency has revised the MACT standards for certain RICE. See 75 FR 9648
and 51570. Although it is difficult to discern from the available data
which types of RICE are driving the facility-wide risk, it is important
to note that the 2005 NEI data on which we modeled risk did not take
into account the recent MACT revisions to the RICE rule. Finally, our
assessment that the potential for significant human health risks due to
multipathway exposures or adverse environmental effects is low has not
changed since proposal (see 76 FR 52774).
    Consistent with the approach established in the Benzene NESHAP, the
EPA weighed all health risk measures and information, including the
maximum individual cancer risk, the cancer incidence, the number of
people exposed to a risk greater than 1-in-1-million, the distribution
of risks in the exposed population and the uncertainty of our risk
calculations in determining whether the risk posed by emissions from
natural gas transmission and storage is acceptable. In this case,
because the MIR is well below 100-in-1-million, and because a number of
other factors indicate relatively low risk concern, including low
cancer incidence, low potential for adverse environmental effects or
human health multi-pathway effects, and unlikely chronic and acute
noncancer health impacts, we conclude that the level of risk associated
with the Natural Gas Transmission and Storage source category MACT
standards (including those MACT standards issued here) is
acceptable.\7\
---------------------------------------------------------------------------

    \7\ We reach the same conclusion even if we do not consider the
new MACT for small glycol dehydrators in our acceptability
determination. Indeed, focusing solely on the standards in the
existing MACT, the level of risk associated with such standards
would remain 20-in-1 million, and thus our acceptability
determination would not change. The glycol dehydrators analyzed all
had risks well below 20-in-1 million.
---------------------------------------------------------------------------

    In making our proposed ample margin of safety determination under
CAA section 112(f)(2), we subsequently evaluated the risk reductions
and costs associated with various emissions control options to
determine whether we should impose additional standards to reduce risks
further. As stated above, we made certain revisions to the risk
assessment in response to comments and the resulting MIR for 40 CFR
part 63, subpart HHH is 20-in-1 million. We have not identified any
emission control options that would reduce emissions and risk
associated with subpart HHH sources for glycol dehydration units. Our
proposed amendment to remove the 0.9 Mg/yr compliance option does not
affect the risk driver, which is fugitive emissions. As a result, we
are retaining the 0.9 Mg/yr compliance option in the final rule.
    We have determined that the risks associated with the level of
emissions allowed by the MACT standards are driven by fugitive
emissions (i.e., leaks). Since a LDAR program is the typical method for
reducing emissions from fugitive sources, we evaluated the costs and
emissions reductions associated with requiring such a program to reduce
risk for this source category. The NEI dataset for the natural gas
transmission and storage source category contains approximately 314
emission points that we characterized as being fugitive in nature.
These emission points are located at 212 facilities. The fugitive
emissions associated with those 212 facilities are 187 tons of HAP.
    In evaluating the effectiveness of a LDAR program at these
facilities we looked at two different LDAR programs--one is a program
equivalent to 40 CFR part 60, subpart VV, and the second is a more
stringent program equivalent to 40 CFR part 60, subpart VVa.\8\ A LDAR
program equivalent to subpart VV can achieve emission reductions of
approximately 51 percent with capital and annual costs of $361,800 and
$142,600 per facility, respectively. Therefore, such a program for 212
facilities would be expected to reduce emissions by 95.4 tons of HAP
and have total capital and annual costs of $76.7 million and $30.2
million, respectively. The cost effectiveness would be approximately
$317,000 per ton of HAP.
---------------------------------------------------------------------------

    \8\ See memorandum titled Equipment Leak Emission Reduction and
Cost Analysis for Well Pads, Gathering and Boosting Stations, and
Transmission and Storage Facilities Using Emission and Cost Data
from the Uniform Standards, dated April 17, 2012.
---------------------------------------------------------------------------

    A LDAR program equivalent to 40 CFR part 60, subpart VVa can
achieve emission reductions of approximately 78 percent overall with
capital and annual costs of $369,500 and $154,300 per facility,
respectively. Therefore, a LDAR program for 212 facilities would be
expected to reduce emissions by 146 tons of HAP with total capital and
annual costs of $78.3 million and $32.7 million, respectively. The cost
effectiveness would be approximately $224,000 per ton of HAP. These
additional control requirements would reduce the MIR from the source
category to approximately 3-in-1 million for the subpart VVa level of
control and 7-in-1-million for the 40 CFR part 60, subpart VV level of
control.
    As explained in the proposal, in accordance with the approach
established in the Benzene NESHAP, we weigh all health risk measures
and information considered in the risk acceptability determination,
along with the costs and economic impacts of emissions controls,
technological feasibility, uncertainties and other relevant factors, in
making our ample margin of safety determination and

deciding whether standards are necessary to reduce risks further.
Considering all of this information, we conclude that the costs of the
options analyzed are not reasonable considering the emissions