6560-50-P
E.O. 12866 NSPS and NESHAP: Oil and Natural Gas Production, Transmission and Distribution 2060-AP76 Proposal 20110728

ENVIRONMENTAL PROTECTION AGENCY

40 CFR Parts 60 and 63

[EPA-HQ-OAR-2010-0505; FRL-      ]

RIN 2060-AP76

Standards of Performance for New Stationary Sources: Oil and Natural Gas Production and Natural Gas Transmission and Distribution; National Emission Standards for Hazardous Air Pollutants From Oil and Natural Gas Production Facilities; and National Emission Standards for Hazardous Air Pollutants From Natural Gas Transmission and Storage Facilities

AGENCY: Environmental Protection Agency (EPA).
ACTION: Proposed rule.
SUMMARY: This action announces how the EPA will address the reviews of the new source performance standards for volatile organic compound and sulfur dioxide emissions from natural gas processing plants. We are adding to the source category list any oil and gas operation not covered by the current listing. This action also includes proposed amendments to the existing new source performance standards for volatile organic compounds from natural gas processing plants and proposed standards for operations that are not covered by the existing new source performance standards. In addition, this action proposes how the EPA will address the residual risk and technology review conducted for the oil and natural gas production and natural gas transmission and storage national emission standards for hazardous air pollutants. This action further proposes standards for emission sources within these two source categories that are not currently addressed, as well as amendments to improve aspects of these national emission standards for hazardous air pollutants related to applicability and implementation. Finally, this action addresses provisions in these new source performance standards and national emission standards for hazardous air pollutants related to emissions during periods of startup, shutdown and malfunction.
DATES: Comments must be received on or before [INSERT DATE 60 DAYS FROM DATE OF PUBLICATION IN THE FEDERAL REGISTER].
Public Hearing. Three public hearings will be held to provide the public an opportunity to provide comments on this proposed rulemaking. One will be held in the Dallas, Texas area, on [INSERT DATE], one in Pittsburgh, Pennsylvania, on [INSERT DATE], and one in Denver, Colorado, on [INSERT DATE]. Each hearing will convene at 10:00 a.m. local time. For additional information on the public hearings and requesting to speak, see the SUPPLEMENTARY INFORMATION section of this preamble.
ADDRESSES: Submit your comments, identified by Docket ID Number EPA-HQ-OAR-2010-0505, by one of the following methods:
      ::	Federal eRulemaking Portal: http://www.regulations.gov: Follow the instructions for submitting comments.
      oo       Agency Website: http://www.epa.gov/oar/docket.html. Follow the instructions for submitting comments on the Air and Radiation Docket website.
       Email<EMAIL_ADDRESS>Include Docket ID Number EPA-HQ-OAR-2010-0505 in the subject line of the message.
       Facsimile:<PHONE_NUMBER>.
       Mail: Attention Docket ID Number EPA-HQ-OAR-2010-0505, 1200 Pennsylvania Ave., NW, Washington, DC 20460. Please include a total of two copies. In addition, please mail a copy of your comments on the information collection provisions to the Office of Information and Regulatory Affairs, Office of Management and Budget (OMB), Attn: Desk Officer for the EPA, 725 17[th] Street, NW, Washington, DC 20503.
       Hand Delivery: United States Environmental Protection Agency, EPA West (Air Docket), Room 3334, 1301 Constitution Ave., NW, Washington, DC 20004, Attention Docket ID Number EPA-HQ-OAR-2010-0505. Such deliveries are only accepted during the Docket's normal hours of operation, and special arrangements should be made for deliveries of boxed information.
Instructions: Direct your comments to Docket ID Number EPA-HQ-OAR-2010-0505. The EPA's policy is that all comments received will be included in the public docket without change and may be made available online at http://www.regulations.gov, including any personal information provided, unless the comment includes information claimed to be confidential business information (CBI) or other information whose disclosure is restricted by statute. Do not submit information that you consider to be CBI or otherwise protected through www.regulations.gov or email. The www.regulations.gov website is an "anonymous access" system, which means the EPA will not know your identity or contact information unless you provide it in the body of your comment. If you send an email comment directly to the EPA without going through www.regulations.gov, your email address will be automatically captured and included as part of the comment that is placed in the public docket and made available on the Internet. If you submit an electronic comment, the EPA recommends that you include your name and other contact information in the body of your comment and with any disk or CD-ROM you submit. If the EPA cannot read your comment due to technical difficulties and cannot contact you for clarification, the EPA may not be able to consider your comment. Electronic files should avoid the use of special characters, any form of encryption, and be free of any defects or viruses. For additional information about the EPA's public docket, visit the EPA Docket Center homepage at http://www.epa.gov/epahome/dockets.htm. For additional instructions on submitting comments, go to section II.C of the SUPPLEMENTARY INFORMATION section of this preamble.
 Docket: All documents in the docket are listed in the www.regulations.gov index. Although listed in the index, some information is not publicly available, e.g., CBI or other information whose disclosure is restricted by statute. Certain other material, such as copyrighted material, is not placed on the Internet and will be publicly available only in hard copy. Publicly available docket materials are available either electronically through www.regulations.gov or in hard copy at the U.S. Environmental Protection Agency, EPA West (Air Docket), Room 3334, 1301 Constitution Ave., NW, Washington, DC 20004. The Public Reading Room is open from 8:30 a.m. to 4:30 p.m., Monday through Friday, excluding legal holidays. The telephone number for the Public Reading Room is<PHONE_NUMBER>, and the telephone number for the Air Docket is<PHONE_NUMBER>.
 FOR FURTHER INFORMATION CONTACT: Bruce Moore, Sector Policies and Programs Division, Office of Air Quality Planning and Standards (E143-01), Environmental Protection Agency, Research Triangle Park, North Carolina 27711, telephone number:<PHONE_NUMBER>; facsimile number:<PHONE_NUMBER>; email address<EMAIL_ADDRESS>
 SUPPLEMENTARY INFORMATION:
 Organization of This Document. The following outline is provided to aid in locating information in this preamble.
I. Preamble Acronyms and Abbreviations
II. General Information
A. Does this action apply to me?
B. Where can I get a copy of this document and other
   related information?
C. What should I consider as I prepare my comments for
   the EPA?
D. When will a public hearing occur?
 III.	Background Information
 A. What are standards of performance and NSPS?
 B. What are NESHAP?
 C. What litigation is related to this proposed action?
D. What is a sector-based approach?
IV. Oil and Natural Gas Sector
V. Summary of Proposed Decisions and Actions
A. What are the proposed revisions to the NSPS?
B. What are the proposed decisions and actions related
   to the NESHAP?
C. What are the proposed notification, recordkeeping and
   reporting requirements for this proposed action?
D. What are the innovative compliance approaches being
   considered?
E. How does the NSPS relate to permitting of sources?
VI. Rationale for Proposed Action for NSPS
A. What did we evaluate relative to NSPS?
B. What are the results of our evaluations and proposed
   actions relative to NSPS?
VII.	Rationale for Proposed Action for NESHAP
A. What data were used for the NESHAP analyses?
B. What are the proposed decisions regarding certain
   unregulated emissions sources?
C. How did we perform the risk assessment and what are
   the results and proposed decisions?
D. How did we perform the technology review and what are
   the results and proposed decisions?
E. What other actions are we proposing?
VIII. What are the cost, environmental, energy and
      economic impacts of the proposed 40 CFR part 60,
      subpart OOOO and amendments to subparts HH and HHH of
      40 CFR part 63?
A. What are the affected sources?
B. How are the impacts for this proposal evaluated?
C. What are the air quality impacts?
D. What are the water quality and solid waste impacts?
E. What are the secondary impacts?
F. What are the energy impacts?
G. What are the cost impacts?
H. What are the economic impacts?
I. What are the benefits?
IX. Request for Comments
X. Submitting Data Corrections
XI. Statutory and Executive Order Reviews
A. Executive Order 12866: Regulatory Planning and
   Review and Executive Order 13563: Improving Regulation
   and Regulatory Review
B. Paperwork Reduction Act
C. Regulatory Flexibility Act
D. Unfunded Mandates Reform Act
E. Executive Order 13132: Federalism
F. Executive Order 13175: Consultation and Coordination
   with Indian Tribal Governments
G. Executive Order 13045: Protection of Children from
   Environmental Health and Safety Risks
H. Executive Order 13211: Actions Concerning Regulations
   That Significantly Affect Energy Supply, Distribution,
   or Use
I. National Technology Transfer and Advancement Act
J. Executive Order 12898: Federal Actions to Address
   Environmental Justice in Minority Populations and Low-
   Income Populations

I. Preamble Acronyms and Abbreviations
	Several acronyms and terms used to describe industrial processes, data inventories and risk modeling are included in this preamble. While this may not be an exhaustive list, to ease the reading of this preamble and for reference purposes, the following terms and acronyms are defined here:
ACGIH	American Conference of Governmental Industrial Hygienists
ADAF	Age-Dependent Adjustment Factors
AEGL 	Acute Exposure Guideline Levels
AERMOD	The air dispersion model used by the HEM-3 model
API	American Petroleum Institute
BACT	Best Available Control Technology
BID	Background Information Document
BPD	Barrels Per Day
BSER	Best System of Emission Reduction
BTEX	Benzene, Ethylbenzene, Toluene and Xylene
CAA	Clean Air Act
CalEPA	California Environmental Protection Agency
CBI	Confidential Business Information
CEM	Continuous Emissions Monitoring
CEMS	Continuous Emissions Monitoring System
CFR	Code of Federal Regulations
CIIT	Chemical Industry Institute of Toxicology
CO	Carbon Monoxide
CO2	Carbon Dioxide
CO2e	Carbon Dioxide Equivalent
DOE	Department of Energy
ECHO	Enforcement and Compliance History Online
e-GGRT	Electronic Greenhouse Gas Reporting Tool
EJ	Environmental Justice
EPA	Environmental Protection Agency
ERPG	Emergency Response Planning Guidelines
ERT	Electronic Reporting Tool
GCG	Gas Condensate Glycol
GHG	Greenhouse Gas
GOR	Gas to Oil Ratio
GWP	Global Warming Potential
HAP	Hazardous Air Pollutants
HEM-3	Human Exposure Model, version 3
HI	Hazard Index
HP	Horsepower
HQ	Hazard Quotient
H2S	Hydrogen Sulfide
ICR	Information Collection Request
IPCC	Intergovernmental Panel on Climate Change
IRIS	Integrated Risk Information System
km	Kilometer
kW	Kilowatts
LAER	Lowest Achievable Emission Rate
lb	Pounds
LDAR	Leak Detection and Repair
MACT	Maximum Achievable Control Technology
MACT Code	Code within the NEI used to identify processes
              included in a source category
Mcf	Thousand Cubic Feet
Mg/yr	Megagrams per year
MIR	Maximum Individual Risk
MIRR	Monitoring, Inspection, Recordkeeping and Reporting
MMtCO2e	Million Metric Tons of Carbon Dioxide Equivalents
NAAQS	National Ambient Air Quality Standards
NAC/AEGL	National Advisory Committee for Acute Exposure Guideline Levels for Hazardous Substances
NAICS	North American Industry Classification System
NAS	National Academy of Sciences
NATA	National Air Toxics Assessment
NEI	National Emissions Inventory
NEMS	National Energy Modeling System
NESHAP 	National Emissions Standards for Hazardous Air
              Pollutants
NGL	Natural Gas Liquids
NIOSH	National Institutes for Occupational Safety
              and Health
NOx	Oxides of Nitrogen
NRC	National Research Council
NSPS	New Source Performance Standards
NSR	New Source Review
NTTAA 	National Technology Transfer and Advancement Act
OAQPS 	Office of Air Quality Planning and Standards
OMB	Office of Management and Budget
PB-HAP 	Hazardous air pollutants known to be persistent and bio-accumulative in the environment
PFE	Potential for Flash Emissions
PM	Particulate Matter
PM2.5	Particulate Matter (2.5 microns and less)
POM	Polycyclic Organic Matter
PPM	Parts Per Million
PPMV	Parts Per Million by Volume
PSIG	Pounds per square inch gauge
PTE	Potential to Emit
QA	Quality Assurance
RACT	Reasonably Available Control Technology
RBLC	RACT/BACT/LAER Clearinghouse
REC	Reduced Emissions Completions
REL	CalEPA Reference Exposure Level
RFA	Regulatory Flexibility Act
RfC	Reference Concentration
RfD	Reference Dose
RIA	Regulatory Impact Analysis
RICE	Reciprocating Internal Combustion Engines
RTR	Residual Risk and Technology Review
SAB	Science Advisory Board
SBREFA	Small Business Regulatory Enforcement Fairness Act
SCC	Source Classification Codes
SCFH	Standard Cubic Feet Per Hour
SCFM	Standard Cubic Feet Per Minute
SCM	Standard Cubic Meters
SCMD	Standard Cubic Meters Per Day
SCOT	Shell Claus Offgas Treatment
SIP	State Implementation Plan
SISNOSE	Significant Economic Impact on a Substantial Number of Small Entities
S/L/T	State and Local and Tribal Agencies
SO2	Sulfur Dioxide
SSM	Startup, Shutdown and Malfunction
STEL	Short-term Exposure Limit
TLV	Threshold Limit Value
TOSHI 	Target Organ-Specific Hazard Index
TPY	Tons per Year
TRIM	Total Risk Integrated Modeling System
TRIM.FaTE	A spatially explicit, compartmental mass balance model that describes the movement and transformation of pollutants over time, through a user-defined, bounded system that includes both biotic and abiotic compartments
TSD	Technical Support Document
UF	Uncertainty Factor
UMRA	Unfunded Mandates Reform Act
URE	Unit Risk Estimate
VCS	Voluntary Consensus Standards
VOC	Volatile Organic Compounds
VRU	Vapor Recovery Unit

 II. General Information
A. Does this action apply to me?
	The regulated industrial source categories that are the subject of this proposal are listed in Table 1 of this preamble. These standards and any changes considered in this rulemaking would be directly applicable to sources as a Federal program. Thus, Federal, state, local and tribal government entities are not affected by this proposed action.
    TABLE 1. INDUSTRIAL SOURCE CATEGORIES AFFECTED BY THIS PROPOSED ACTION
                                    Category
 NAICS code[1]
                         Examples of regulated entities
 Industry . . . .
 211111
 Crude Petroleum and Natural Gas Extraction

 211112
 Natural Gas Liquid Extraction

 221210
 Natural Gas Distribution

 486110
 Pipeline Distribution of Crude Oil

 486210
 Pipeline Transportation of Natural Gas
 Federal government
 . . . .
 Not affected.
 State/local/tribal government
 . . . .
 Not affected.
 [1] North American Industry Classification System.

 	This table is not intended to be exhaustive, but rather provides a guide for readers regarding entities likely to be affected by this action. To determine whether your facility would be regulated by this action, you should examine the applicability criteria in the regulations. If you have any questions regarding the applicability of this action to a particular entity, contact the person listed in the preceding FOR FURTHER INFORMATION CONTACT section.
B. Where can I get a copy of this document and other related information?
	In addition to being available in the docket, an electronic copy of this proposal will also be available on the EPA's website. Following signature by the EPA Administrator, a copy of this proposed action will be posted on the EPA's website at the following address: http://www.epa.gov/airquality/oilandgas.
	Additional information is available on the EPA's Residual Risk and Technology Review (RTR) website at http://www.epa.gov/ttn/atw/rrisk/oarpg.html. This information includes the most recent version of the rule, source category descriptions, detailed emissions and other data that were used as inputs to the risk assessments.
C. What should I consider as I prepare my comments for the EPA?
Submitting CBI. Do not submit information containing CBI to the EPA through www.regulations.gov or email. Clearly mark the part or all of the information that you claim to be CBI. For CBI information on a disk or CD ROM that you mail to the EPA, mark the outside of the disk or CD ROM as CBI and then identify electronically within the disk or CD ROM the specific information that is claimed as CBI. In addition to one complete version of the comment that includes information claimed as CBI, a copy of the comment that does not contain the information claimed as CBI must be submitted for inclusion in the public docket. If you submit a CD ROM or disk that does not contain CBI, mark the outside of the disk or CD ROM clearly that it does not contain CBI. Information not marked as CBI will be included in the public docket and the EPA's electronic public docket without prior notice. Information marked as CBI will not be disclosed except in accordance with procedures set forth in 40 CFR part 2. Send or deliver information identified as CBI only to the following address: Roberto Morales, OAQPS Document Control Officer (C404-02), Environmental Protection Agency, Office of Air Quality Planning and Standards, Research Triangle Park, North Carolina 27711, Attention Docket ID Number EPA-HQ-OAR-2010-0505.
D. When will a public hearing occur?
	We will hold three public hearings, one in the Dallas, Texas area, one in Pittsburgh, Pennsylvania, and one in Denver, Colorado. If you are interested in attending or speaking at one of the public hearings, contact Ms. Joan Rogers at<PHONE_NUMBER> by [INSERT DATE 11 DAYS FROM DATE OF PUBLICATION IN THE FEDERAL REGISTER]. Details on the public hearings will be provided in a separate notice and we will specify the time and date of the public hearings on http://www.epa.gov/airquality/oilandgas. If no one requests to speak at one of the public hearings [INSERT DATE 11 DAYS FROM DATE OF PUBLICATION IN THE FEDERAL REGISTER], then that public hearing will be cancelled without further notice.
III.	Background Information
A. What are standards of performance and NSPS?
1. What is the statutory authority for standards of performance and NSPS?
	Section 111 of the Clean Air Act (CAA) requires the EPA Administrator to list categories of stationary sources, if such sources cause or contribute significantly to air pollution, which may reasonably be anticipated to endanger public health or welfare. The EPA must then issue performance standards for such source categories. A performance standard reflects the degree of emission limitation achievable through the application of the "best system of emission reduction" (BSER) which the EPA determines has been adequately demonstrated. The EPA may consider certain costs and nonair quality health and environmental impact and energy requirements when establishing performance standards. Whereas CAA section 112 standards are issued for existing and new stationary sources, standards of performance are issued for new and modified stationary sources. These standards are referred to as new source performance standards (NSPS). The EPA has the authority to define the source categories, determine the pollutants for which standards should be developed, identify the facilities within each source category to be covered and set the emission level of the standards.
	CAA section 111(b)(1)(B) requires the EPA to "at least every 8 years review and, if appropriate, revise" performance standards unless the "Administrator determines that such review is not appropriate in light of readily available information on the efficacy" of the standard. When conducting a review of an existing performance standard, the EPA has discretion to revise that standard to add emission limits for pollutants or emission sources not currently regulated for that source category.
      In setting or revising a performance standard, CAA section 111(a)(1) provides that performance standards are to "reflect the degree of emission limitation achievable through the application of the best system of emission reduction which (taking into account the cost of achieving such reduction and any nonair quality health and environmental impact and energy requirements) the Administrator determines has been adequately demonstrated." In this notice, we refer to this level of control as the BSER. In determining BSER, we typically conduct a technology review that identifies what emission reduction systems exist and how much they reduce air pollution in practice. Next, for each control system identified, we evaluate its costs, secondary air benefits (or disbenefits) resulting from energy requirements and nonair quality impacts such as solid waste generation. Based on our evaluation, we would determine BSER. The resultant standard is usually a numerical emissions limit, expressed as a performance level (i.e., a rate-based standard or percent control), that reflects the BSER. Although such standards are based on the BSER, the EPA may not prescribe a particular technology that must be used to comply with a performance standard, except in instances where the Administrator determines it is not feasible to prescribe or enforce a standard of performance. Typically, sources remain free to elect whatever control measures that they choose to meet the emission limits. Upon promulgation, a NSPS becomes a national standard to which all new, modified or reconstructed sources must comply.
2. What is the regulatory history regarding performance standards for the oil and natural gas sector?
	In 1979, the EPA listed crude oil and natural gas production on its priority list of source categories for promulgation of NSPS (44 FR 49222, August 21, 1979). On June 24, 1985 (50 FR 26122), the EPA promulgated a NSPS for the source category that addressed volatile organic compound (VOC) emissions from leaking components at onshore natural gas processing plants (40 CFR part 60, subpart KKK). On October 1, 1985 (50 FR 40158), a second NSPS was promulgated for the source category that regulates sulfur dioxide (SO2) emissions from natural gas processing plants (40 CFR part 60, subpart LLL). Other than natural gas processing plants, EPA has not previously set NSPS for a variety of oil and natural gas operations.
B. What are NESHAP?
1. What is the statutory authority for NESHAP?
      Section 112 of the CAA establishes a two-stage regulatory process to address emissions of hazardous air pollutants (HAP) from stationary sources. In the first stage, after the EPA has identified categories of sources emitting one or more of the HAP listed in section 112(b) of the CAA, section 112(d) of the CAA calls for us to promulgate national emission standards for hazardous air pollutants (NESHAP) for those sources. "Major sources" are those that emit or have the potential to emit (PTE) 10 tons per year (tpy) or more of a single HAP or 25 tpy or more of any combination of HAP. For major sources, these technology-based standards must reflect the maximum degree of emission reductions of HAP achievable (after considering cost, energy requirements and nonair quality health and environmental impacts) and are commonly referred to as maximum achievable control technology (MACT) standards.
      MACT standards are to reflect application of measures, processes, methods, systems or techniques, including, but not limited to, measures which, (1) reduce the volume of or eliminate pollutants through process changes, substitution of materials or other modifications, (2) enclose systems or processes to eliminate emissions, (3) capture or treat pollutants when released from a process, stack, storage or fugitive emissions point, (4) are design, equipment, work practice or operational standards (including requirements for operator training or certification) or (5) are a combination of the above. CAA section 112(d)(2)(A)-(E). The MACT standard may take the form of a design, equipment, work practice or operational standard where the EPA first determines either that, (1) a pollutant cannot be emitted through a conveyance designed and constructed to emit or capture the pollutant or that any requirement for or use of such a conveyance would be inconsistent with law or (2) the application of measurement methodology to a particular class of sources is not practicable due to technological and economic limitations. CAA sections 112(h)(1)-(2).
      The MACT "floor" is the minimum control level allowed for MACT standards promulgated under CAA section 112(d)(3), and may not be based on cost considerations. For new sources, the MACT floor cannot be less stringent than the emission control that is achieved in practice by the best-controlled similar source. The MACT floors for existing sources can be less stringent than floors for new sources, but they cannot be less stringent than the average emission limitation achieved by the best-performing 12 percent of existing sources in the category or subcategory (or the best-performing five sources for categories or subcategories with fewer than 30 sources). In developing MACT standards, we must also consider control options that are more stringent than the floor. We may establish standards more stringent than the floor based on the consideration of the cost of achieving the emissions reductions, any nonair quality health and environmental impacts and energy requirements.
      The EPA is then required to review these technology-based standards and to revise them "as necessary (taking into account developments in practices, processes, and control technologies)" no less frequently than every 8 years, under CAA section 112(d)(6). In conducting this review, the EPA is not obliged to completely recalculate the prior MACT determination. NRDC v. EPA, 529 F.3d 1077, 1084 (D.C. Cir. 2008).
      The second stage in standard-setting focuses on reducing any remaining "residual" risk according to CAA section 112(f). This provision requires, first, that the EPA prepare a Report to Congress discussing (among other things) methods of calculating risk posed (or potentially posed) by sources after implementation of the MACT standards, the public health significance of those risks, and the EPA's recommendations as to legislation regarding such remaining risk. The EPA prepared and submitted this report (Residual Risk Report to Congress, EPA - 453/R - 99 - 001) in March 1999. Congress did not act in response to the report, thereby triggering the EPA's obligation under CAA section 112(f)(2) to analyze and address residual risk.
      CAA section 112(f)(2) requires us to determine for source categories subject to MACT standards, whether the emissions standards provide an ample margin of safety to protect public health. If the MACT standards for HAP "classified as a known, probable, or possible human carcinogen do not reduce lifetime excess cancer risks to the individual most exposed to emissions from a source in the category or subcategory to less than 1-in-1 million," the EPA must promulgate residual risk standards for the source category (or subcategory), as necessary, to provide an ample margin of safety to protect public health. In doing so, the EPA may adopt standards equal to existing MACT standards if the EPA determines that the existing standards are sufficiently protective. NRDC v. EPA, 529 F.3d 1077, 1083 (D.C. Cir. 2008). ("If EPA determines that the existing technology-based standards provide an "ample margin of safety," then the Agency is free to readopt those standards during the residual risk rulemaking.") The EPA must also adopt more stringent standards, if necessary, to prevent an adverse environmental effect, but must consider cost, energy, safety and other relevant factors in doing so.
      Section 112(f)(2) of the CAA expressly preserves our use of a two-step process for developing standards to address any residual risk and our interpretation of "ample margin of safety" developed in the National Emission Standards for Hazardous Air Pollutants: Benzene Emissions from Maleic Anhydride Plants, Ethylbenzene/Styrene Plants, Benzene Storage Vessels, Benzene Equipment Leaks, and Coke By-Product Recovery Plants (Benzene NESHAP) (54 FR 38044, September 14, 1989). The first step in this process is the determination of acceptable risk. The second step provides for an ample margin of safety to protect public health, which is the level at which the standards are set (unless a more stringent standard is required to prevent, taking into consideration costs, energy, safety, and other relevant factors, an adverse environmental effect).
      The terms "individual most exposed," "acceptable level," and "ample margin of safety" are not specifically defined in the CAA. However, CAA section 112(f)(2)(B) preserves the interpretation set out in the Benzene NESHAP, and the United States Court of Appeals for the District of Columbia Circuit in NRDC v. EPA, 529 F.3d 1077, concluded that the EPA's interpretation of subsection 112(f)(2) is a reasonable one. See NRDC v. EPA, 529 F.3d at 1083 (D.C. Cir., "[S]ubsection 112(f)(2)(B) expressly incorporates EPA's interpretation of the Clean Air Act from the Benzene standard, complete with a citation to the Federal Register"). (D.C. Cir. 2008). See also, A Legislative History of the Clean Air Act Amendments of 1990, volume 1, p. 877 (Senate debate on Conference Report). We notified Congress in the Residual Risk Report to Congress that we intended to use the Benzene NESHAP approach in making CAA section 112(f) residual risk determinations (EPA - 453/R - 99 - 001, p. ES - 11).
      In the Benzene NESHAP, we stated as an overall objective:
      * * * in protecting public health with an ample margin of safety, we strive to provide maximum feasible protection against risks to health from hazardous air pollutants by, (1) protecting the greatest number of persons possible to an individual lifetime risk level no higher than approximately 1-in-1 million; and (2) limiting to no higher than approximately 1-in-10 thousand [i.e., 100-in-1 million] the estimated risk that a person living near a facility would have if he or she were exposed to the maximum pollutant concentrations for 70 years.
      The Agency also stated that, "The EPA also considers incidence (the number of persons estimated to suffer cancer or other serious health effects as a result of exposure to a pollutant) to be an important measure of the health risk to the exposed population. Incidence measures the extent of health risk to the exposed population as a whole, by providing an estimate of the occurrence of cancer or other serious health effects in the exposed population." The Agency went on to conclude that "estimated incidence would be weighed along with other health risk information in judging acceptability." As explained more fully in our Residual Risk Report to Congress, the EPA does not define "rigid line[s] of acceptability," but considers rather broad objectives to be weighed with a series of other health measures and factors (EPA - 453/R - 99 - 001, p. ES - 11). The determination of what represents an "acceptable" risk is based on a judgment of "what risks are acceptable in the world in which we live" (Residual Risk Report to Congress, p. 178, quoting the Vinyl Chloride decision at 824 F.2d 1165) recognizing that our world is not risk-free.
      In the Benzene NESHAP, we stated that "EPA will generally presume that if the risk to [the maximum exposed] individual is no higher than approximately 1-in-10 thousand, that risk level is considered acceptable." 54 FR 38045. We discussed the maximum individual lifetime cancer risk (or maximum individual risk (MIR)) as being "the estimated risk that a person living near a plant would have if he or she were exposed to the maximum pollutant concentrations for 70 years." Id. We explained that this measure of risk "is an estimate of the upper bound of risk based on conservative assumptions, such as continuous exposure for 24 hours per day for 70 years." Id. We acknowledge that maximum individual lifetime cancer risk "does not necessarily reflect the true risk, but displays a conservative risk level which is an upper-bound that is unlikely to be exceeded." Id.
      Understanding that there are both benefits and limitations to using maximum individual lifetime cancer risk as a metric for determining acceptability, we acknowledged in the 1989 Benzene NESHAP that "consideration of maximum individual risk * * * must take into account the strengths and weaknesses of this measure of risk." Id. Consequently, the presumptive risk level of 100-in-1 million (1-in-10 thousand) provides a benchmark for judging the acceptability of maximum individual lifetime cancer risk, but does not constitute a rigid line for making that determination.
      The Agency also explained in the 1989 Benzene NESHAP the following: "In establishing a presumption for MIR, rather than a rigid line for acceptability, the Agency intends to weigh it with a series of other health measures and factors. These include the overall incidence of cancer or other serious health effects within the exposed population, the numbers of persons exposed within each individual lifetime risk range and associated incidence within, typically, a 50-kilometer (km) exposure radius around facilities, the science policy assumptions and estimation uncertainties associated with the risk measures, weight of the scientific evidence for human health effects, other quantified or unquantified health effects, effects due to co-location of facilities and co-emission of pollutants." Id.
      In some cases, these health measures and factors taken together may provide a more realistic description of the magnitude of risk in the exposed population than that provided by maximum individual lifetime cancer risk alone. As explained in the Benzene NESHAP, "[e]ven though the risks judged "acceptable" by the EPA in the first step of the Vinyl Chloride inquiry are already low, the second step of the inquiry, determining an "ample margin of safety," again includes consideration of all of the health factors, and whether to reduce the risks even further." In the ample margin of safety decision process, the Agency again considers all of the health risks and other health information considered in the first step. Beyond that information, additional factors relating to the appropriate level of control will also be considered, including costs and economic impacts of controls, technological feasibility, uncertainties and any other relevant factors. Considering all of these factors, the Agency will establish the standard at a level that provides an ample margin of safety to protect the public health, as required by CAA section 112(f). 54 FR 38046.
2. How do we consider the risk results in making decisions?
      As discussed in the previous section of this preamble, we apply a two-step process for developing standards to address residual risk. In the first step, the EPA determines if risks are acceptable. This determination "considers all health information, including risk estimation uncertainty, and includes a presumptive limit on maximum individual lifetime [cancer] risk (MIR) of approximately 1-in-10 thousand [i.e., 100-in-1 million]." 54 FR 38045. In the second step of the process, the EPA sets the standard at a level that provides an ample margin of safety "in consideration of all health information, including the number of persons at risk levels higher than approximately 1-in-1 million, as well as other relevant factors, including costs and economic impacts, technological feasibility, and other factors relevant to each particular decision." Id.
      In past residual risk determinations, the EPA presented a number of human health risk metrics associated with emissions from the category under review, including: The MIR; the numbers of persons in various risk ranges; cancer incidence; the maximum noncancer hazard index (HI); and the maximum acute noncancer hazard. In estimating risks, the EPA considered source categories under review that are located near each other and that affect the same population. The EPA provided estimates of the expected difference in actual emissions from the source category under review and emissions allowed pursuant to the source category MACT standard. The EPA also discussed and considered risk estimation uncertainties. The EPA is providing this same type of information in support of these actions.
      The Agency acknowledges that the Benzene NESHAP provides flexibility regarding what factors the EPA might consider in making our determinations and how they might be weighed for each source category. In responding to comment on our policy under the Benzene NESHAP, the EPA explained that: "The policy chosen by the Administrator permits consideration of multiple measures of health risk. Not only can the MIR figure be considered, but also incidence, the presence of noncancer health effects, and the uncertainties of the risk estimates. In this way, the effect on the most exposed individuals can be reviewed as well as the impact on the general public. These factors can then be weighed in each individual case. This approach complies with the Vinyl Chloride mandate that the Administrator ascertain an acceptable level of risk to the public by employing [her] expertise to assess available data. It also complies with the Congressional intent behind the CAA, which did not exclude the use of any particular measure of public health risk from the EPA's consideration with respect to CAA section 112 regulations, and, thereby, implicitly permits consideration of any and all measures of health risk which the Administrator, in [her] judgment, believes are appropriate to determining what will `protect the public health.'"
      For example, the level of the MIR is only one factor to be weighed in determining acceptability of risks. The Benzene NESHAP explains "an MIR of approximately 1-in-10 thousand should ordinarily be the upper end of the range of acceptability. As risks increase above this benchmark, they become presumptively less acceptable under CAA section 112, and would be weighed with the other health risk measures and information in making an overall judgment on acceptability. Or, the Agency may find, in a particular case, that a risk that includes MIR less than the presumptively acceptable level is unacceptable in the light of other health risk factors." Similarly, with regard to the ample margin of safety analysis, the Benzene NESHAP states that: "EPA believes the relative weight of the many factors that can be considered in selecting an ample margin of safety can only be determined for each specific source category. This occurs mainly because technological and economic factors (along with the health-related factors) vary from source category to source category."
3. What is the regulatory history regarding NESHAP for the oil and natural gas sector?
	On July 16, 1992 (57 FR 31576), the EPA published a list of major and area sources for which NESHAP are to be published (i.e., the source category list). Oil and natural gas production facilities were listed as a category of major sources. On February 12, 1998 (63 FR 7155), the EPA amended the source category list to add Natural Gas Transmission and Storage as a major source category.
	On June 17, 1999 (64 FR 32610), the EPA promulgated MACT standards for the Oil and Natural Gas Production and Natural Gas Transmission and Storage major source categories. The Oil and Natural Gas Production NESHAP (40 CFR part 63, subpart HH) contains standards for HAP emissions from glycol dehydration process vents, storage vessels and natural gas processing plant equipment leaks. The Natural Gas Transmission and Storage NESHAP (40 CFR part 63, subpart HHH) contains standards for glycol dehydration process vents.
	In addition to these NESHAP for major sources, the EPA also promulgated NESHAP for the Oil and Natural Gas Production area source category on January 3, 2007 (72 FR 26). These area source standards, which are based on generally available control technology, are also contained in 40 CFR part 63, subpart HH. This proposed action does not impact these area source standards.
C. What litigation is related to this proposed action?
	On January 14, 2009, pursuant to section 304(a)(2) of the CAA, WildEarth Guardians and the San Juan Citizens Alliance filed a Complaint alleging that the EPA failed to meet its obligations under CAA sections 111(b)(1)(B), 112(d)(6) and 112(f)(2) to take actions relative to the review/revision of the NSPS and the NESHAP with respect to the Oil and Natural Gas Production source category. On February 4, 2010, the Court entered a consent decree
requiring the EPA to sign by July 28, 2011, proposed
standards and/or determinations not to issue standards pursuant to CAA sections 111(b)(1)(B), 112(d)(6) and 112(f)(2) and to take final action by February 28, 2012.
D. What is a sector-based approach?
	Sector-based approaches are based on integrated assessments that consider multiple pollutants in a comprehensive and coordinated manner to manage emissions and CAA requirements. One of the many ways we can address sector-based approaches is by reviewing multiple regulatory programs together whenever possible, consistent with all applicable legal requirements. This approach essentially expands the technical analyses on costs and benefits of particular technologies, to consider the interactions of rules that regulate sources. The benefit of multi-pollutant and sector-based analyses and approaches includes the ability to identify optimum strategies, considering feasibility, cost impacts and benefits across the different pollutant types while streamlining administrative and compliance complexities and reducing conflicting and redundant requirements, resulting in added certainty and easier implementation of control strategies for the sector under consideration. In order to benefit from a sector-based approach for the oil and gas industry, the EPA analyzed how the NSPS and NESHAP under consideration relate to each other and other regulatory requirements currently under review for oil and gas facilities. In this analysis, we looked at how the different control requirements that result from these requirements interact, including the different regulatory deadlines and control equipment requirements that result, the different reporting and recordkeeping requirements and opportunities for states to account for reductions resulting from this rulemaking in their State Implementation Plans (SIP). The requirements analyzed affect criteria pollutant, HAP and methane emissions from oil and natural gas processes and cover the NSPS and NESHAP reviews. As a result of the sector-based approach, this rulemaking will reduce conflicting and redundant requirements. Also, the sector-based approach facilitated the streamlining of monitoring, recordkeeping and reporting requirements, thus, reducing administrative and compliance complexities associated with complying with multiple regulations. In addition, the sector-based approach promotes a comprehensive control strategy that maximizes the co-control of multiple regulated pollutants while obtaining emission reductions as co-benefits.
IV. Oil and Natural Gas Sector
	The oil and natural gas sector includes operations involved in the extraction and production of oil and natural gas, as well as the processing, transmission and distribution of natural gas. Specifically for oil, the sector includes all operations from the well to the point of custody transfer at a petroleum refinery. For natural gas, the sector includes all operations from the well to the customer. The oil and natural gas operations can generally be separated into four segments: (1) Oil and natural gas production, (2) natural gas processing, (3) natural gas transmission and (4) natural gas distribution. Each of these segments is briefly discussed below.
	Oil and natural gas production includes both onshore and offshore operations. Production operations include the wells and all related processes used in the extraction, production, recovery, lifting, stabilization, separation or treating of oil and/or natural gas (including condensate). Production components may include, but are not limited to, wells and related casing head, tubing head and "Christmas tree" piping, as well as pumps, compressors, heater treaters, separators, storage vessels, pneumatic devices and dehydrators. Production operations also include the well drilling, completion and workover processes and includes all the portable non-self-propelled apparatus associated with those operations. Production sites include not only the "pads" where the wells are located, but also include stand-alone sites where oil, condensate, produced water and gas from several wells may be separated, stored and treated. The production sector also includes the low pressure, small diameter, gathering pipelines and related components that collect and transport the oil, gas and other materials and wastes from the wells to the refineries or natural gas processing plants. None of the operations upstream of the natural gas processing plant are covered by the existing NSPS. Offshore oil and natural gas production occurs on platform structures that house equipment to extract oil and gas from the ocean or lake floor and that process and/or transfer the oil and gas to storage, transport vessels or onshore. Offshore production can also include secondary platform structures connected to the platform structure, storage tanks associated with the platform structure and floating production and offloading equipment.
	There are three basic types of wells: Oil wells, gas wells and associated gas wells. Oil wells can have "associated" natural gas that is separated and processed or the crude oil can be the only product processed. Once the crude oil is separated from the water and other impurities, it is essentially ready to be transported to the refinery via truck, railcar or pipeline. We consider the oil refinery sector separately from the oil and natural gas sector. Therefore, at the point of custody transfer at the refinery, the oil leaves the oil and natural gas sector and enters the petroleum refining sector.
	Natural gas is primarily made up of methane. However, whether natural gas is associated gas from oil wells or non-associated gas from gas or condensate wells, it commonly exists in mixtures with other hydrocarbons. These hydrocarbons are often referred to as natural gas liquids (NGL). They are sold separately and have a variety of different uses. The raw natural gas often contains water vapor, hydrogen sulfide (H2S), carbon dioxide (CO2), helium, nitrogen and other compounds. Natural gas processing consists of separating certain hydrocarbons and fluids from the natural gas to produced "pipeline quality" dry natural gas. While some of the processing can be accomplished in the production segment, the complete processing of natural gas takes place in the natural gas processing segment. Natural gas processing operations separate and recover NGL or other non-methane gases and liquids from a stream of produced natural gas through components performing one or more of the following processes: Oil and condensate separation, water removal, separation of NGL, sulfur and CO2 removal, fractionation of natural gas liquid and other processes, such as the capture of CO2 separated from natural gas streams for delivery outside the facility. Natural gas processing plants are the only operations covered by the existing NSPS.
	The pipeline quality natural gas leaves the processing segment and enters the transmission segment. Pipelines in the natural gas transmission segment can be interstate pipelines that carry natural gas across state boundaries or intrastate pipelines, which transport the gas within a single state. While interstate pipelines may be of a larger diameter and operated at a higher pressure, the basic components are the same. To ensure that the natural gas flowing through any pipeline remains pressurized, compression of the gas is required periodically along the pipeline. This is accomplished by compressor stations usually placed between 40 and 100 mile intervals along the pipeline. At a compressor station, the natural gas enters the station, where it is compressed by reciprocating or centrifugal compressors.
	In addition to the pipelines and compressor stations, the natural gas transmission segment includes underground storage facilities. Underground natural gas storage includes subsurface storage, which typically consists of depleted gas or oil reservoirs and salt dome caverns used for storing natural gas. One purpose of this storage is for load balancing (equalizing the receipt and delivery of natural gas). At an underground storage site, there are typically other processes, including compression, dehydration and flow measurement.
	The distribution segment is the final step in delivering natural gas to customers. The natural gas enters the distribution segment from delivery points located on interstate and intrastate transmission pipelines to business and household customers. The delivery point where the natural gas leaves the transmission segment and enters the distribution segment is often called the "citygate." Typically, utilities take ownership of the gas at the citygate. Natural gas distribution systems consist of thousands of miles of piping, including mains and service pipelines to the customers. Distribution systems sometimes have compressor stations, although they are considerably smaller than transmission compressor stations. Distribution systems include metering stations, which allow distribution companies to monitor the natural gas in the system. Essentially, these metering stations measure the flow of gas and allow distribution companies to track natural gas as it flows through the system.
	Emissions can occur from a variety of processes and points throughout the oil and natural gas sector. Primarily, these emissions are organic compounds such as methane, ethane, VOC and organic HAP. The most common organic HAP are n-hexane and BTEX compounds (benzene, toluene, ethylbenzene and xylenes). Hydrogen sulfide (H2S) and sulfur dioxide (SO2) are emitted from production and processing operations that handle and treat "sour gas." Sour gas is defined as natural gas with a maximum H2S content of 0.25 gr/100 scf (4ppmv) along with the presence of CO2.
	In addition, there are significant emissions associated with the reciprocating internal combustion engines and combustion turbines that power compressors throughout the oil and natural gas sector. However, emissions from internal combustion engines and combustion turbines are covered by regulations specific to engines and turbines and, thus, are not addressed in this action.
V. Summary of Proposed Decisions and Actions
	Pursuant to CAA sections 111(b), 112(d)(2), 112(d)(6) and 112(f), we are proposing to revise the NSPS and NESHAP relative to oil and gas to include the standards and requirements summarized in this section. More details of the rationale for these proposed standards and requirements are provided in sections VI and VII of this preamble. In addition, as part of these rationale discussions, we solicit public comment and data relevant to several issues.   The comments we receive during the public comment period will help inform the rule development process as we work toward promulgating a final action.
A. What are the proposed revisions to the NSPS?
      We reviewed the two NSPS that apply to the oil and natural gas industry. Based on our review, we believe that the requirements at 40 CFR part 60, subpart KKK, should be updated to reflect requirements in 40 CFR part 60, subpart VVa for controlling VOC equipment leaks at processing plants. We also believe that the requirements at 40 CFR part 60, subpart LLL, for controlling SO2 emissions from natural gas processing plants should be strengthened for facilities with the highest sulfur feed rates and the highest H2S concentrations. For a more detailed discussion, please see section VI.B.1 of this preamble.
      In addition, there are significant VOC emissions from oil and natural gas operations that are not covered by the two existing NSPS, including other emissions at processing plants and emissions from upstream production, as well as transmission and storage facilities. In the 1984 notice that listed source categories (including Oil and Natural Gas) for promulgation of NSPS, we noted that there were discrepancies between the source category names on the list and those in the background document, and we clarified our intent to address all sources under an industry heading at the same time. See 44 FR 49222, 49224-49225. We, therefore, believe that the currently listed Oil and Natural Gas source category covers all operations in this industry (i.e., production, processing, transmission, storage and distribution). To the extent there are oil and gas operations not covered by the currently listed Oil and Natural Gas source category, pursuant to CAA section 111(b), we hereby modify the category list to include all operations in the oil and natural gas sector. Section 111(b) of the CAA gives the EPA broad authority and discretion to list and establish NSPS for a category that, in the Administrator's judgment, causes or contributes significantly to air pollution which may reasonably be anticipated to endanger public health or welfare. Pursuant to CAA section 111(b), we are modifying the source category list to include any oil and gas operation not covered by the current listing and evaluating emissions from all oil and gas operations at the same time.
      We are also proposing standards for several new oil and natural gas affected facilities. The proposed standards would apply to affected facilities that commence construction, reconstruction or modification after [INSERT DATE OF PUBLICATION IN THE FEDERAL REGISTER]. These standards, which include requirements for VOC, would be contained in a new subpart, 40 CFR part 60, subpart OOOO. Subpart OOOO would incorporate 40 CFR part 60, subpart KKK and 40 CFR part 60, subpart LLL, thereby having in this one subpart, all standards that are applicable to the new and modified affected facilities described above. We also propose to amend the title of subparts KKK and LLL, accordingly, to apply only to affected facilities already subject to those subparts. Those operations would not become subject to subpart OOOO unless they triggered applicability based on new or modified affected facilities under subpart OOOO.
	We are proposing operational standards for completions of hydraulically fractured gas wells. Based on our review, we identified two subcategories of fractured gas wells for which well completions are conducted. For non-exploratory and non-delineation wells, the proposed operational standards would require reduced emission completion (REC), commonly referred to as "green completion," in combination with pit-flaring of gas not suitable for entering the gathering line. For exploratory and delineation wells (these wells generally are not in close proximity to a gathering line), we proposed an operational standard that would require pit flaring. Well completions subject to the standards would be limited to gas well completions following hydraulic fracturing operations. These completions include those conducted at newly drilled and fractured wells, as well as completions conducted following refracturing operations at various times over the life of the well. We have determined that a completion associated with refracturing performed at an existing well (i.e., a well existing prior to (INSERT DATE OF PUBLICATION IN THE FEDERAL REGISTER)) is considered a modification under CAA section 111(a), because physical change occurs to the existing well resulting in emissions increase during the refracturing and completion operation. A detailed discussion of this determination is presented in the Technical Support Document (TSD) in the docket. Therefore, the proposed standards would apply to completions at new gas wells that are fractured or refractured along with completions associated with fracturing or refracturing of existing gas wells. The modification determination and resultant applicability of NSPS to the completion operation following fracturing or refracturing of existing gas wells (i.e., wells existing before [INSERT DATE OF PUBLICATION IN THE FEDERAL REGISTER] would be limited strictly to the wellhead, well bore, casing and tubing, and any conveyance through which gas is vented to the atmosphere and not be extended beyond the wellhead to other ancillary components that may be at the well site such as existing storage vessels, process vessels, separators, dehydrators or any other components or apparatus.
      We are also proposing VOC standards to reduce emissions from gas-driven pneumatic devices. We are proposing that each pneumatic device is an affected facility. Accordingly, the proposed standards would apply to each newly installed pneumatic device (including replacement of an existing device). At gas processing plants, we are proposing a zero emission limit for each individual pneumatic controller. The proposed emission standards would reflect the emission level achievable from the use of non-gas-driven pneumatic controllers. At other locations, we are proposing a bleed limit of 6 standard cubic feet of gas per hour for an individual pneumatic controller, which would reflect the emission level achievable from the use of low bleed gas-driven pneumatic controllers. In both cases, the standards provide exemptions for certain applications based on functional considerations.
	In addition, the proposed rule would require measures to reduce VOC emissions from centrifugal and reciprocating compressors. As explained in more detail below in section VI.B.4, we are proposing equipment standards for centrifugal compressors. The proposed standards would require the use of dry seal systems. However, we are aware that some owners and operators may need to use centrifugal compressors with wet seals, and we are soliciting comment on the suitability of a compliance option allowing the use of wet seals combined with routing of emissions from the seal liquid through a closed vent system to a control device as an acceptable alternative to installing dry seals.
      Our review of reciprocating compressors found that piston rod packing wear produces fugitive emissions that cannot be captured and conveyed to a control device. As a result, we are proposing operational standards for reciprocating compressors, such that the proposed rule would require replacement of the rod packing based on hours of usage. The owner or operator of a reciprocating compressor affected facility would be required to monitor the duration (in hours) that the compressor is operated. When the hours of operation reaches 26,000 hours, the owner or operator would be required to change the rod packing immediately. However, to avoid unscheduled shutdowns when 26,000 hours is reached, owners and operators could track hours of operation such that packing replacement could be coordinated with planned maintenance shutdowns before hours of operation reached 26,000. Some operators may prefer to replace the rod packing on a fixed schedule to ensure that the hours of operation would not reach 26,000 hours. We solicit comment on the appropriateness of a fixed replacement frequency and other considerations that would be associated with regular replacement.
      We are also proposing VOC standards for new or modified storage vessels. The proposed rule, which would apply to individual vessels, would require that vessels meeting certain specifications achieve at least 95-percent reduction in VOC emissions. Requirements would apply to vessels with a throughput of 1 barrel of condensate per day or 20 barrels of crude oil per day. These thresholds are equivalent to VOC emissions of about 6 tpy.
      For gas processing plants, we are updating the requirements for leak detection and repair (LDAR) to reflect procedures and leak thresholds established by 40 CFR 60, subpart VVa. The existing NSPS requires 40 CFR part 60, subpart VV procedures and thresholds.
      For 40 CFR part 60, subpart LLL, which regulates SO2 emissions from natural gas processing plants, we determined that affected facilities with sulfur feed rate of at least 5 long tons per day or H2S concentration in the acid gas stream of at least 50 percent can achieve up to 99.9- percent SO2 control, which is greater than the existing standard. Therefore, we are proposing revision to the performance standards in subpart LLL as a result of this review. For a more detailed discussion of this proposed determination, please see section VI.B.1 of this preamble.
      We are proposing to address compliance requirements for periods of startup, shutdown and malfunction (SSM) for 40 CFR part 60, subpart OOOO. The SSM changes are discussed in detail in section VI.B.5 below. In addition, we are proposing to incorporate the requirements in 40 CFR part 60, subpart KKK and 40 CFR part 60, subpart LLL into the new subpart OOOO so that all requirements applicable to the new and modified facilities would be in one subpart. This would simplify and streamline compliance efforts on the part of the oil and natural gas industry and could minimize duplication of notification, recordkeeping and reporting.
B. What are the proposed decisions and actions related to the NESHAP?
	This section summarizes the results of our RTR for the Oil and Natural Gas Production and the Natural Gas Transmission and Storage source categories and our proposed decisions concerning these two 1999 NESHAP.
1. Addressing Unregulated Emissions Sources
	Pursuant to CAA sections 112(d)(2) and (3), we are proposing MACT standards for subcategories of glycol dehydrators for which standards were not previously developed (hereinafter referred to as the "small dehydrators"). In the Oil and Natural Gas Production source category, the subcategory consists of glycol dehydrators with an actual annual average natural gas flowrate less than 85,000 standard cubic meters per day (scmd) or actual average benzene emissions less than 0.9 megagrams per year (Mg/yr). In the Natural Gas Transmission and Storage source category, the subcategory consists of glycol dehydrators with an actual annual average natural gas flowrate less than 283,000 scmd or actual average benzene emissions less than 0.9 Mg/yr.
	The proposed MACT standards for the subcategory of small dehydrators at oil and gas production facilities would require that existing affected sources meet a unit-specific BTEX limit of 1.10x10[-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 x10[-6] grams BTEX/scm-ppmv. At natural gas transmission and storage affected sources, the proposed MACT standard for the subcategory of small dehydrators would require that existing affected sources meet a unit-specific BTEX emission limit of 6.42x10[-5] grams BTEX/scm-ppmv and that new affected sources meet a BTEX limit of 1.10 x10[-5] grams BTEX/scm-ppmv.
	We are also proposing MACT standards for storage vessels that are currently not regulated under the Oil and Natural Gas Production NESHAP. The current MACT standards apply only to storage vessels with the potential for flash emissions (PFE). As explained in section VII, the original MACT analysis accounted for all storage vessels. We are, therefore, proposing to apply the current MACT standards of 95-percent emission reduction to every storage vessel at major source oil and natural gas production facilities. In conjunction with this change, we are proposing to amend the definition of associated equipment to exclude all storage vessels, and not just those with the PFE, from being considered "associated equipment." This means that emissions from all storage vessels, and not just those from storage vessels with the PFE, are to be included in the major source determination.
2. What are the proposed decisions and actions related to the risk review?
	For both the Oil and Natural Gas Production and the Natural Gas Transmission and Storage source categories, we find that the current levels of emissions allowed by the MACT reflect acceptable levels of risk; however, the level of emissions allowed by the alternative compliance option for glycol dehydrator MACT (i.e., the option of reducing benzene emissions to less than 0.9 Mg/yr in lieu of the MACT standard of 95-percent control) reflects an unacceptable level of risk. We are, therefore, proposing to eliminate the 0.9 Mg/yr alternative compliance option.
	In addition, we are proposing that the MACT for these two oil and gas source categories, as revised per above, provide an ample margin of safety to protect public health and prevent adverse environmental effects.
3. What are the proposed decisions and actions related to the technology reviews of the existing NESHAP?
	For both the Oil and Natural Gas Production and the Natural Gas Transmission and Storage source categories, we are proposing no revisions to the existing NESHAP pursuant to section 112(d)(6) of the CAA.
4. What other actions are we proposing?
	We are proposing an alternative performance test for non-flare, combustion control devices. This test is to be conducted by the combustion control device manufacturer to demonstrate the destruction efficiency achieved by a specific model of combustion control device. This would allow a source to purchase a performance tested device for installation at their site without being required to conduct a site-specific performance test. A definition for "flare" is being proposed in the NESHAP to clarify which combustion control devices fall under the manufacturers' performance testing alternative, and to clarify which devices must be performance tested.
	We are also proposing to: Revise the parametric monitoring calibration provisions; require periodic performance testing where applicable; remove the allowance of a design analysis for all control devices other than condensers; remove the requirement for a minimum residence time for an enclosed combustion device; and add recordkeeping and reporting requirements to document carbon replacement intervals. These changes are being proposed to bring the NESHAP up-to-date based on what we have learned regarding control devices and compliance since the original promulgation date.
	In addition, we are proposing the elimination of the SSM exemption in the Oil and Natural Gas Production and the Natural Gas Transmission and Storage NESHAP. As discussed in more detail below in section VII, consistent with Sierra Club v. EPA, 551 F.3d 1019 (D.C. Cir. 2010), the EPA is proposing that the established standards in these two NESHAP apply at all times. We are proposing to revise Table 2 to both 40 CFR part 63, subpart HH and 40 CFR part 63, subpart HHH to indicate that certain 40 CFR part 63 general provisions relative to SSM do not apply, including: 40 CFR 63.6 (e)(1)(i) and (ii), 40 CFR 63.6(e)(3) (SSM plan requirement), 40 CFR 63.6(f)(1); 40 CFR 63.7(e)(1), 40 CFR 63.8(c)(1)(i) and (iii), and the last sentence of 40 CFR 63.8(d)(3); 40 CFR 63.10(b)(2)(i),(ii), (iv) and (v); 40 CFR 63.10(c)(10), (11) and (15); and 40 CFR 63.10(d)(5). We are also proposing to: (1) Revise 40 CFR 63.771(d)(4)(i) and 40 CFR 63.1281(d)(4)(i) regarding operation of the control device to be consistent with the SSM compliance requirements; and (2) revise the SSM-associated reporting and recordkeeping requirements in 40 CFR 63.774, 40 CFR 63.775, 40 CFR 63.1284 and 40 CFR 63.1285 to require reporting and recordkeeping for periods of malfunction. In addition, as explained below, we are proposing to add an affirmative defense to civil penalties for exceedances of emission limits caused by malfunctions, as well as criteria for establishing the affirmative defense.
	The EPA has attempted to ensure that we have neither overlooked nor failed to propose to remove from the existing text any provisions that are inappropriate, unnecessary or redundant in the absence of the SSM exemption, nor included any such provisions in the proposed new regulatory language. We are specifically seeking comment on whether there are any such provisions that we have inadvertently overlooked or incorporated.
	We are also revising the applicability provisions of 40 CFR part 63, subpart HH to clarify requirements regarding PTE determination and the scope of a facility subject to subpart HH. Lastly, we are proposing several editorial corrections and plain language revisions to improve these rules.
C. What are the proposed notification, recordkeeping and reporting requirements for this proposed action?
1. What are the proposed notification, recordkeeping and reporting requirements for the proposed NSPS?
	The proposed 40 CFR part 60, subpart OOOO includes new requirements for several operations for which there are no existing Federal standards. Most notably, as discussed in sections V.A and VI.B of this preamble, the proposed NSPS will cover completions and recompletions of hydraulically fractured gas wells. We estimate that over 20,000 completions and recompletions annually will be subject to the proposed requirements. Given the number of these operations, we believe that notification and reporting must be streamlined to the extent possible to minimize undue burden on owners and operators, as well as state, local and tribal agencies. In section V.D of this preamble, we discuss some innovative implementation approaches being considered and seek comment on these and other potential methods of streamlining notification and reporting for well completions covered by the proposed rule.
	Owners or operators are required to submit initial notifications and annual reports, and to retain records to assist in documenting that they are complying with the provisions of the NSPS. These notification, recordkeeping and reporting activities include both requirements of the 40 CFR part 60 General Provisions, as well as requirements specific to 40 CFR part 60, subpart OOOO.
      Owners or operators of affected facilities (except for pneumatic controller and gas wellhead affected sources) must submit an initial notification within 1 year after becoming subject to 40 CFR part 60, subpart OOOO or by 1 year after the publication of the final rule in the Federal Register, whichever is later. For pneumatic controllers, owners and operators are not required to submit an initial notification, but instead are required to report the installation of these affected facilities in their facility's annual report. Owners or operators of wellhead affected facilities (well completions) would also be required to submit a 30-day advance notification of each well completion subject to the NSPS. In addition, annual reports are due 1 year after initial startup date for your affected facility or 1 year after the date of publication of the final rule in the Federal Register, whichever is later. The notification and annual reports must include information on all affected facilities owned or operated that were new, modified or reconstructed sources during the reporting period. A single report may be submitted covering multiple affected facilities, provided that the report contains all the information required by 40 CFR 60.5420(b). This information includes general information on the facility (i.e., company name and address, etc.), as well as information specific to individual affected facilities.
      For wellhead affected facilities, this information includes details of each well completion during the period, including duration of periods of gas recovery, flaring and venting. For centrifugal compressor affected facilities, information includes documentation that the compressor is fitted with dry seals. For reciprocating compressors, information includes the cumulative hours of operation of each compressor and records of rod packing replacement.
      Information for pneumatic device affected facilities includes location and manufacturer specifications of each pneumatic controller installed during the period and documentation that supports any exemption claimed allowing use of high bleed controllers. For controllers installed at gas processing plants, the owner or operator would document the use of non-gas driven devices. For controllers installed in locations other than at gas processing plants, owners or operators would provide manufacturer's specifications that document bleed rate not exceeding 6 cubic feet per hour.
      For storage vessel affected facilities, required report information includes information that documents control device compliance, if applicable. For vessels with throughputs below 1 barrel of condensate per day and 21 barrels of crude oil per day, required information also includes calculations or other documentation of the throughput. For onshore gas processing plants, semi-annual reports are required, and include information on number of pressure relief devices, number of pressure relief devices for which leaks were detected and pressure relief devices for which leaks were not repaired, as required in 40 CFR 60.5396 of subpart OOOO.
      Records must be retained for 5 years and generally consist of the same information required in the initial notification and annual and semiannual reports.
2. What are the proposed amendments to notification, recordkeeping and reporting requirements for the NESHAP?
	We are proposing to revise certain recordkeeping requirements of 40 CFR part 63, subpart HH and 40 CFR part 63, subpart HHH. Specifically, we are proposing that facilities using carbon adsorbers as a control device keep records of their carbon replacement schedule and records for each carbon replacement. In addition, owners and operators are required to keep records of the occurrence and duration of each malfunction or operation of the air pollution control equipment and monitoring equipment.
	In addition, in conjunction with the proposed MACT standards for small glycol dehydration units and storage vessels that do not have the PFE in the proposed amendment to 40 CFR part 63, subpart HH, we are proposing that owners and operators of affected small glycol dehydration units and storage vessels submit an initial notification within 1 year after becoming subject to subpart HH or by 1 year after the publication of the final rule in the Federal Register, whichever is later.
	Similarly, in conjunction with the proposed MACT standards for small glycol dehydration units in the proposed 40 CFR part 63, subpart HHH amendments, we are proposing that owners and operators of small glycol dehydration units submit an initial notification within 1 year after becoming subject to subpart HHH or by 1 year after the publication of the final rule in the Federal Register, whichever is later. Affected sources under either 40 CFR part 63, subpart HH or subpart HHH that plan to be area sources by the compliance dates will be required to submit a notification describing their schedule for the actions planned to achieve area source status.
	The proposed amendments to the NESHAP also include additional requirements for the contents of the periodic reports. For both 40 CFR part 63, subpart HH and 40 CFR part 63, subpart HHH, we are proposing that the periodic reports also include periodic test results and information regarding any carbon replacement events that occurred during the reporting period.
3. How is information submitted using the Electronic Reporting Tool (ERT)?
Performance test data are an important source of information that the EPA uses in compliance determinations, developing and reviewing standards, emission factor development, annual emission rate determinations and other purposes. In these activities, the EPA has found it ineffective and time consuming, not only for owners and operators, but also for regulatory agencies, to locate, collect and submit performance test data because of varied locations for data storage and varied data storage methods. In recent years, though, stack testing firms have typically collected performance test data in electronic format, making it possible to move to an electronic data submittal system that would increase the ease and efficiency of data submittal and improve data accessibility.
Through this proposal, the EPA is taking a step to increase the ease and efficiency of data submittal and improve data accessibility. Specifically, the EPA is proposing that owners and operators of oil and natural gas sector facilities submit electronic copies of required performance test reports to the EPA's WebFIRE database. The WebFIRE database was constructed to store performance test data for use in developing emission factors. A description of the WebFIRE database is available at http://cfpub.epa.gov/oarweb/index.cfm?action=fire.main.
As proposed above, data entry would be through an electronic emissions test report structure called the Electronic Reporting Tool (ERT). The ERT will be able to transmit the electronic report through the EPA's Central Data Exchange network for storage in the WebFIRE database making submittal of data very straightforward and easy. A description of the ERT can be found at http://www.epa.gov/ttn/chief/ert/ert_tool.html.
The proposal to submit performance test data electronically to the EPA would apply only to those performance tests conducted using test methods that will be supported by the ERT. The ERT contains a specific electronic data entry form for most of the commonly used EPA reference methods. A listing of the pollutants and test methods supported by the ERT is available at http://www.epa.gov/ttn/chief/ert/ert_tool.html. We believe that industry would benefit from this proposed approach to electronic data submittal. Having these data, the EPA would be able to develop improved emission factors, make fewer information requests, and promulgate better regulations.
One major advantage of the proposed submittal of performance test data through the ERT is a standardized method to compile and store much of the documentation required to be reported by this rule. Another advantage is that the ERT clearly states testing information that would be required. Another important benefit of submitting these data to the EPA at the time the source test is conducted is that it should substantially reduce the effort involved in data collection activities in the future. When the EPA has performance test data in hand, there will likely be fewer or less substantial data collection requests in conjunction with prospective required residual risk assessments or technology reviews. This would result in a reduced burden on both affected facilities (in terms of reduced manpower to respond to data collection requests) and the EPA (in terms of preparing and distributing data collection requests and assessing the results).
State, local and tribal agencies could also benefit from more streamlined and accurate review of electronic data submitted to them. The ERT would allow for an electronic review process rather than a manual data assessment making review and evaluation of the source provided data and calculations easier and more efficient. Finally, another benefit of the proposed data submittal to WebFIRE electronically is that these data would greatly improve the overall quality of existing and new emissions factors by supplementing the pool of emissions test data for establishing emissions factors and by ensuring that the factors are more representative of current industry operational procedures. A common complaint heard from industry and regulators is that emission factors are outdated or not representative of a particular source category. With timely receipt and incorporation of data from most performance tests, the EPA would be able to ensure that emission factors, when updated, represent the most current range of operational practices. In summary, in addition to supporting regulation development, control strategy development and other air pollution control activities having an electronic database populated with performance test data would save industry, state, local, tribal agencies and the EPA significant time, money and effort while also improving the quality of emission inventories and, as a result, air quality regulations.
D. What are the innovative compliance approaches being considered?
	Given the potential number and diversity of sources affected by this action, we are exploring optional approaches to provide the regulated community, the regulators and the public a more effective mechanism that maximizes compliance and transparency while minimizing burden.
      Under a traditional approach, owners or operators would provide notifications and keep records of information required by the NSPS. In addition, they would certify compliance with the NSPS as part of a required annual report that would include compliance-related information, such as details of each well completion event and information documenting compliance with other requirements of the NSPS. The EPA, state or local agency would then physically inspect the affected facilities and/or audit the records retained by the owner or operator. As an alternative to the traditional approach, we are seeking an innovative way to provide for more transparency to the public and less burden on the regulatory agencies and owners and operators, especially as it relates to modification of existing sources through recompletions of hydraulically fractured gas wells. These innovative approaches would provide compliance assurance in light of the absence of requirements for CAA title V permitting of non-major sources.
      Section V.E of this preamble discusses permitting implications associated with the NSPS and presents a proposed rationale for exempting non-major sources subject to the NSPS from title V permitting requirements. As discussed in sections V.A, V.C and VI.B of this preamble, the proposed NSPS will cover completions and recompletions of hydraulically fractured gas wells. We estimate that over 20,000 completions and recompletions annually will be subject to the proposed requirements. As a result, we believe that notification and reporting associated with well completions must be streamlined to the extent possible to minimize undue burden on owners and operators, as well as state, local and tribal agencies. Though the requirements being proposed here are based on the traditional approach to compliance and do not include specific regulatory provisions for innovative compliance tools, we have included discussions below that describe how some of these optional tools could work, and we will consider providing for such options in the final action. Further, we request comments and suggestions on all aspects of the innovative compliance approaches discussed below and how they may be implemented appropriately. We are seeking comment regarding the scope of application of one or more of these approaches, i.e., which provisions of the standards being proposed here would be suitable for specific compliance approaches, and whether the approaches should be alternatives to the requirements in the regulations.
      The guiding principles we are following in considering these approaches to compliance are: (1) Simplicity and ease of understanding and implementation; (2) transparency and public accessibility; (3) electronic implementation where appropriate; and (4) encouragement of compliance by making compliance easier than noncompliance. Below are some tools that, when used in tandem with emissions limits and operational standards, the Agency believes could both assure compliance and transparency, while minimizing burden on affected sources and regulatory agencies.
1. Registration of Wells and Advance Notification of Planned Completions
	Although the proposed NSPS will not require approval to drill or complete wells, it is important that regulatory agencies know when completions of hydraulically fractured wells are to be performed. Notification should occur sufficiently in advance to allow for inspections or audits to certify or verify that the operator will have in place and use the appropriate controls during the completion. To that end, the proposed NSPS requires a 30-day advance notification of each completion or recompletion of a hydraulically fractured gas well. The advance notification would require that owners or operators provide the anticipated date of the completion, the geographic coordinates of the well and identifying information concerning the owner or operator and responsible company official. We believe this notification requirement serves as the registration requirement and could be streamlined through optional electronic reporting with web-based public access or other methods. We seek comment on potential methodologies that would minimize burden on operators, while providing timely and useful information for regulators and the public. We also solicit comment on provisions for a follow-up notification one or two days before an impending completion via telephone or by electronic means, since it is difficult to predict exactly when a well will be ready for completion a month in advance. However, we would expect an owner or operator to provide the follow-up notification only in cases where the completion date was expected to deviate from the original date provided. We ask for suggestions regarding how much advance notification is needed and the most effective method of providing sufficient and accurate advance notification of well completions.
2. Third Party Verification
	To complement the annual compliance certification required under the proposed NSPS, we are considering and seeking comment on the potential use of third party verification to assure compliance. Since the emission sources in the oil and natural gas sector, especially well completions, are widely geographically dispersed (often in very remote locations), compliance assurance can be very difficult and burdensome for state, local and tribal agencies and EPA permitting staff, inspectors and compliance officers. Additionally, we believe that verification of the data collection, compilation and calculations by an independent and impartial third party could facilitate the demonstration of compliance for the public. Verification of emissions data can also be beneficial to owners and operators by providing certainty of compliance status.
	As mentioned above, notification and reporting requirements associated with well completions are likely applications for third party verification used in tandem with the required annual compliance certification. The third party verification program could be used in a variety of ways to ease regulatory burden on the owners and operators and to leverage compliance assurance efforts of the EPA and state, local and tribal agencies. The third party agent could serve as a clearinghouse for notifications, records and annual compliance certifications submitted by owners and operators. This would provide online access to completion information by regulatory agencies and the public. Having notifications submitted to the clearinghouse would relieve state, local and tribal agencies of the burden of receiving thousands of paper or email well completion notifications each year, yet still provide them quick access to the information. Using a third party agent, it is possible that notifications of well completions could be submitted with an advance period much less than 30 days that could make a 2 day follow-up notification unnecessary. The clearinghouse could also house information on past completions and copies of compliance certifications. We seek comment on whether annual reports for well completions would be needed if a suitable third party verification program was in place and already housed that same information. We also solicit comment on the range of potential activities the third party verification program could handle with regard to well completions.
      In this proposed action, there are also provisions for applying third party verification to the required electronic reporting using the ERT (see section V.C.3 above for a discussion of the ERT). As stated above, all sources must use the ERT to submit all performance test reports (required in 40 CFR parts 60, 61 and 63) to the EPA. There is an option in the ERT for state, local and tribal agencies to review and verify that the information submitted to the EPA is truthful, accurate and complete. Third party verifiers could be contractors or other personnel familiar with oil and natural gas exploration and production. We are seeking comment on appropriate third party reviewers and qualifications and registration requirements under such a program. We want to state clearly here that third party verification would not supersede or substitute for inspections or audit of data and information by state, local and tribal agencies and the EPA.
      Potential issues with third party verification include costs incurred by industry and approval of third party verifiers. The cost of third party verification would be borne by the affected industries. We are seeking comment on whether third party verification paid for by industry would result in impartial, accurate and complete data information. The EPA, working with state, local and tribal agencies and industry, would expect to develop guidance for third party verifiers. We are seeking comment on whether or not the EPA should approve third party verifiers.
3. Electronic Reporting Using Existing Mechanisms
	The proposed 40 CFR part 60, subpart OOOO and final Greenhouse Gas (GHG) Mandatory Reporting Rule, 40 CFR part 98, subpart W, provide details on flare and vented emission sources and how to estimate their emissions. We solicit comment on requiring sources to electronically submit their emissions data for the oil and gas rules proposed here. The EPA's Electronic Greenhouse Gas Reporting Tool (e-GGRT) for 40 CFR part 98, subpart W, while used to report emissions at the emissions source level (e.g., well completions, well unloading, compressors, gas plant leaks, etc.), will aggregate emissions at the basin level for e-reporting purposes. As a result, it may be difficult to merge reporting under NSPS subpart OOOO with GHG Reporting Rule subpart W methane reporting, especially if manual reporting is used. However, since the operator would have these emissions details at the individual well level (because that will be how they would develop their basin-wide estimates), we do not believe it would be a significant burden to require owners or operators to report the data they already have for subpart W in an ERT for NSPS and NESHAP compliance purposes. However, if the e-GGRT is not structured to provide for reporting of other pollutants besides GHG (e.g., VOC and HAP), then there may be some modification of the database required to accommodate the other pollutants.
4. Provisions for Encouraging Innovative Technology
	The oil and natural gas industry has a long history of innovation in developing new exploration and production methods, along with techniques to minimize product losses and reduce adverse environmental impacts. These efforts are often undertaken with tremendous amounts of research, including pilot applications at operating facilities in the field. Absent regulation, these developmental activities, some of which ultimately are not successful, can proceed without risk of violation of any standards. However, as more emission sources in this source category are covered by regulation, as in the case of the action being proposed here, there likely will be situations where innovation and development of new control techniques potentially could be stifled by risk of violation.
      We believe it is important to facilitate, not hinder, innovation and continued development of new technology that can result in enhanced environmental performance of facilities and sources affected by the EPA's regulations. However, any approaches to accommodate technology development must be designed and implemented in accordance with the CAA and other statutes. We seek comment on approaches that may be suitable for allowing temporary field testing of technology in development. These approaches could include not only established procedures under the CAA and its implementing regulations, but new ways to apply or interpret these provisions to avoid impeding innovation while remaining environmentally responsible and legal.
E. How does the NSPS Relate to Permitting of Sources?
1. How does this action affect permitting requirements?
	The proposed rules do not change the Federal requirements for determining whether oil and gas sources are major sources for purposes of nonattainment major New Source Review (NSR), prevention of significant deterioration, CAA title V, or HAP major sources pursuant to CAA section 112. Specifically, if an owner or operator is not currently required to get a major NSR or title V permit for oil and gas sources, including well completions, it would not be required to get a major NSR or title V permit as a result of these proposed standards. EPA-approved state and local major source permitting programs would not be affected. That is, state and local agencies with EPA-approved programs will still make case-by-case major source determinations for purposes of major NSR and title V, relying on the regulatory criteria, as explained in the McCarthy Memo. Consistent with the McCarthy Memo, whether or not a permitting authority should aggregate two or more pollutant-emitting activities into a single major stationary source for purposes of NSR and title V remains a case-by-case decision in which permitting authorities retain the discretion to consider the factors relevant to the specific circumstances of the permitted activities.
	In addition, the proposed standards would not change the requirements for determining whether oil and gas sources are subject to minor NSR. Nor would the proposed standards affect existing EPA-approved state and local minor NSR rules, as well as policies and practices implementing those rules. Many state and local agencies have already adopted minor NSR permitting programs that provide for control of emissions from relatively small emission sources, including various pieces of equipment used in oil and gas fields. State and local agencies would be able to continue to use any EPA-approved General Permits, Permits by Rule, and other similar streamlining mechanisms to permit oil and gas sources such as wells. We recently promulgated the final Tribal Minor NSR rules for use in issuing minor issue permits on tribal lands, where many oil and gas sources are located.
	The proposed standards will lead to better control of and reduced emissions from oil and gas production, gas processing and transmission and storage, including wells. In some instances, we anticipate that complying with the NSPS would reduce emissions from these smaller sources to below the minor source applicability thresholds. In those cases, sources that would otherwise have been subject to minor NSR would not need to get minor NSR permits as a result of being subject to the NSPS. Accordingly, the number of minor NSR permits, as well as the Agency resources needed to issue them, would be reduced.
	We expect the emission reductions achieved from the proposed standards to significantly improve ozone nonattainment problems in areas where oil and gas production occurs. Strategies for attaining and maintaining the national ambient air quality standards (NAAQS) are a function of SIP (or, in some instances, Federal Implementation Plans and Tribal Implementation Plans) pursuant to CAA section 110. In developing plans to attain and maintain the NAAQS, EPA works with state, local or Tribal agencies to account for growth and develop overall control strategies that address existing and expected emissions. The reductions achieved by the standards will make it easier for state and local agencies to plan for and to attain and maintain the ozone NAAQS.
2. How does this action affect applicability of CAA title V?
	Under section 502(a) of the CAA, the EPA may exempt one or more non-major sources subject to CAA section 111 (NSPS) standards from the requirements of title V if the EPA finds that compliance with such requirements is "impracticable, infeasible, or unnecessarily burdensome" on such sources. The EPA determine whether to exempt a non-major source from title V at the time we issue the relevant CAA section 111 standards (40 CFR 70.3(b)(2)). We are proposing in this action to exempt from the requirements of title V non-major sources that would be subject to the proposed NSPS for well completions, pneumatic devices, compressors, and/or storage vessels. These non-major sources (hereinafter referred to as the "oil and gas NSPS non-major sources") would not be required to obtain title V permits solely as a result of being subject to one or more of the proposed NSPS identified above (hereinafter referred to as the "proposed NSPS"); however, if they were otherwise required to obtain title V permits, such requirement(s) would not be affected by the proposed exemption.	Consistent with the statute, the EPA believes that compliance with title V permitting is "unnecessarily burdensome" for the oil and gas NSPS non-major sources. The EPA's inquiry into whether this criterion was satisfied is based primarily upon consideration of the following four factors: (1) Whether title V would result in significant improvements to the compliance requirements that we are proposing for the oil and gas NSPS affected non-major sources; (2) whether title V permitting would impose a significant burden on these non-major sources and whether that burden would be aggravated by any difficulty these sources may have in obtaining assistance from permitting agencies; (3) whether the costs of title V permitting for these non-major sources would be justified, taking into consideration any potential gains in compliance likely to occur for such sources; and (4) whether there are implementation and enforcement programs in place that are sufficient to assure compliance with the proposed Oil and Natural Gas NSPS without relying on title V permits. Not all of the four factors must weigh in favor of an exemption. See 70 FR 75320, 75323 (Title V Exemption Rule). Instead, the factors are to be considered in combination and the EPA determines whether the factors, taken together, support an exemption from title V for the oil and gas non-major sources. Additionally, consistent with the guidance provided by the legislative history of CAA section 502(a), we considered whether exempting the Oil and Natural Gas NSPS non-major sources would adversely affect public health, welfare or the environment. The first factor is whether title V would result in significant improvements to the compliance requirements in the proposed NSPS. A finding that title V would not result in significant improvements to the compliance requirements in the proposed NSPS would support a conclusion that title V permitting is "unnecessary" for non-major sources subject to the Oil and Natural Gas Production NSPS.
	One way that title V may improve compliance is by requiring monitoring (including recordkeeping designed to serve as monitoring) to assure compliance with permit terms and conditions reflecting the emission limitations and control technology requirements imposed in the standard. See 40 CFR 70.6(c)(1) and 40 CFR 71.6(c)(1). The "periodic monitoring" provisions of 40 CFR 70.6(a)(3)(i)(B) and 40 CFR 71.6(a)(3)(i)(B) require new monitoring to be added to the permit when the underlying standard does not already require "periodic testing or instrumental or noninstrumental monitoring (which may consist of recordkeeping designed to serve as monitoring)." In addition, title V imposes a number of recordkeeping and reporting requirements that may be important for assuring compliance. These include requirements for a monitoring report at least every 6 months, prompt reports of deviations, and an annual compliance certification. See 40 CFR 70.6(a)(3) and 40 CFR 71.6(a)(3), 40 CFR 70.6(c)(1) and 40 CFR 71.6(c)(1), and 40 CFR 70.6(c)(5) and 40 CFR 71.6(c)(5). To determine whether title V permits would add significant compliance requirements to the proposed NSPS, we compared the title V monitoring, recordkeeping and reporting requirements mentioned above to those requirements proposed for the Oil and Natural Gas NSPS affected facilities.
	For wellhead affected facilities (well completions), the proposed NSPS would require (1) 30-day advance notification of each well completion to be performed; (2) noninstrumental monitoring, which is achieved through documentation and recordkeeping of procedures followed during each completion, including total duration of the completion event, amount of time gas is recovered using reduced emission completion techniques, amount of time gas is combusted, amount of time gas is vented to the atmosphere and justification for periods when gas is combusted or vented rather than being recovered; (3) reports of cases where well completions were not performed in compliance with the NSPS; (4) annual reports that document all completions performed during the reporting period (a single report may be used to document multiple completions conducted by a single owner or operator during the reporting period); and (5) annual compliance certifications submitted with the annual report.
	These monitoring, recordkeeping and reporting requirements in the proposed NSPS for well completions are sufficient to ensure that the Administrator, the state, local and tribal agencies and the public are aware of completion events before they are performed to provide opportunity for inspection. Sufficient documentation would also be required to be retained and reported to the Administrator to assure compliance with the NSPS for well completions. In light of the above, we have determined that additional monitoring through title V is not needed and that the monitoring, recordkeeping and reporting requirements described above are sufficient to assure compliance with the proposed requirements for well completions.
      With respect to storage vessels, the proposed NSPS would require 95-percent control of VOC emissions. The proposed standard could be met by a vapor recovery unit, a flare control device or other control device. The proposed NSPS would require an initial performance test followed by continuous monitoring of the control device used to meet the 95-percent control. We believe that the monitoring requirements described above are sufficient to assure compliance with the proposed NSPS for storage vessels and, therefore, additional monitoring through title V is not needed. In addition to monitoring, as part of the first factor, we have considered the extent to which title V could potentially enhance compliance through recordkeeping or reporting requirements. The proposed NSPS would require (1) construction, startup and modification notifications, as required by 40 CFR 60.7(a); and (2) annual reports that identify all storage vessel affected facilities of the owner or operator and documentation of periods of non-compliance. The proposed NSPS would also require records documenting liquid throughput of condensate or crude oil (to determine applicability), as provided for in the proposed rule. Recordkeeping would also include records of the initial performance test and other information that document compliance with applicable emission limit. These requirements are similar to those under title V. In light of the above, we believe that the monitoring, recordkeeping and reporting requirements described above are sufficient to assure compliance with the proposed NSPS for storage vessels.
	For pneumatic controllers, centrifugal compressors and reciprocating compressors, the proposed NSPS are in the form of operational, work practice or equipment standards. For each of these affected facilities, the proposed NSPS would require: (1) Construction, startup and modification notifications, as required by 40 CFR 60.7(a); (2) annual reports; (3) for each pneumatic controller installed or modified (including replacement of an existing controller), records of location and date of installation and documentation that each controller emits no more than the applicable emission limit or is exempt (with rationale for the exemption); (4) for each centrifugal compressor, records that document that each new or modified compressor is equipped with dry seals; and (5) for each new or modified reciprocating compressor, records of rod packing replacement, including elapsed operating hours since the previous rod packing installation.
	For these other affected sources described above, the proposed NSPS provide monitoring in the form of recordkeeping (as described above) that would assure compliance with the proposed operational, work practice or equipment standards. Monitoring by means other than recordkeeping would not be practical or appropriate for these standards. Records are required to ensure that these standards and practices are followed. We believe that the monitoring, recordkeeping and reporting requirements described above are sufficient to assure compliance with the proposed NSPS for pneumatic controllers and compressors.
      We acknowledge that title V might provide for additional compliance requirements for these non-major sources, but we have determined, as explained above, that the monitoring, recordkeeping and reporting requirements in this proposed NSPS are sufficient to assure compliance with the proposed standards for well completions, storage vessels, pneumatic controllers and compressors. Further, given the nature of some of the operations and the types of the requirements at issue, the additional compliance requirements under title V would not significantly improve the compliance requirements in this proposed NSPS. For instance, well completions occur over a very short period (generally 3 to 10 days), and the proposed NSPS for pneumatic controllers and centrifugal compressors can be met by simply installing the equipment that meet the proposed emission limit; therefore, the semi-annual reporting requirement under title V would not improve compliance with these proposed NSPS and, in fact, may seem inappropriate for such short term operations.
      For the reasons stated above, we believe that title V would not result in significant improvements to the compliance requirements that are provided in this proposed NSPS. Therefore, the first factor supports a conclusion that title V permitting is "unnecessary" for non-major sources subject to the Oil and Natural Gas NSPS.
      The second factor we considered is whether title V permitting would impose significant burdens on the oil and natural gas NSPS non-major sources and whether that burden would be aggravated by any difficulty these sources may have in obtaining assistance from permitting agencies. Subjecting any source to title V permitting imposes certain burdens and costs that do not exist outside of the title V program. EPA estimated that the average cost of obtaining and complying with a title V permit was $65,700 per source for a 5-year permit period, including fees. See Information Collection Request (ICR) for Part 70 Operating Permit Regulations, January 2007, EPA ICR Number 1587.07. EPA does not have specific estimates for the burdens and costs of permitting the oil and gas NSPS non-major sources; however, there are certain activities associated with the 40 CFR part 70 and 40 CFR part 71 rules. These activities are mandatory and impose burdens on the any facility subject to title V. They include reading and understanding permit program regulations; obtaining and understanding permit application forms; answering follow-up questions from permitting authorities after the application is submitted; reviewing and understanding the permit; collecting records; preparing and submitting monitoring reports; preparing and submitting prompt deviation reports, as defined by the state, which may include a combination of written, verbal and other communications methods; collecting information, preparing and submitting the annual compliance certification; preparing applications for permit revisions every 5 years; and, as needed, preparing and submitting applications for permit revisions. In addition, although not required by the permit rules, many sources obtain the contractual services of consultants to help them understand and meet the permitting program's requirements. The ICR for 40 CFR part 70 provides additional information on the overall burdens and costs, as well as the relative burdens of each activity described here. Also, for a more comprehensive list of requirements imposed on 40 CFR part 70 sources (hence, burden on sources), see the requirements of 40 CFR 70.3, 40 CFR 70.5, 40 CFR 70.6, and 40 CFR 70.7. The activities described above, which are quite extensive and time consuming, would be a significant burden on the non-major sources that would be subject to the proposed NSPS, in particular for well completion and/or pneumatic devices, considering the short duration of a well completion and the one time equipment installation of a pneumatic controller for meeting the proposed NSPS. Furthermore, some of the non-major sources that would be subject to the proposed NSPS may be small entities that may lack the technical resources and, therefore, need assistance from the permitting authorities to comply with the title V permitting requirements. Based on our projections, over 20,000 well completions (for both new hydraulically fractured gas wells and for existing gas wells that are subsequently fractured or re-fractured) will be performed each year. For pneumatic controller affected facilities, we estimate that approximately 14,000 new controllers would be subject to the NSPS each year. Our estimated numbers of affected facilities that would be subject to the proposed NSPS for storage vessels and compressors are smaller (around 500 compressors and 300 storage vessels). Although we do not know the total number of non-major sources that would be subject to the proposed NSPS, based on the estimated numbers of affected facilities, we anticipate a significant increase in the number of permit applications that permitting authorities would have to process each year. This significant burden on the permitting authorities raises a concern with the potential difficulty or delay that the small entities may face in obtaining sufficient assistance from the permitting authorities.
      The third factor we considered is whether the costs of title V permitting for these area sources would be justified, taking into consideration any potential gains in compliance likely to occur for such sources. We concluded, in considering the first factor, that the monitoring, recordkeeping and reporting requirements in this proposed NSPS assure compliance with the proposed standards, that title V would not result in significant improvement to these compliance requirements and, that, in some instances, certain title V compliance requirements may not be appropriate. In addition, as discussed above in our consideration of the second factor, we have concerns with the potential burdens that title V may impose on these sources. In addition, below in our consideration of the fourth factor, we find that there are adequate implementation and enforcement programs in place to assure compliance with the proposed NSPS. In light of the above, we find that the costs of title V permitting are not justified for the sources we propose to exempt. Accordingly, the third factor supports title V exemption for the oil and gas NSPS non-major sources.
      The fourth factor we considered is whether there are implementation and enforcement programs in place that are sufficient to assure compliance with the proposed NSPS for oil and gas sources without relying on title V permits.  The CAA provides States the opportunity to take delegation of NSPS. Before the EPA will delegate the program, the EPA will evaluate the state programs to ensure that states have adequate capability to enforce the CAA section 111 regulations and provide assurances that they will enforce the NSPS. In addition, EPA retains authority to enforce this NSPS anytime under CAA sections 111, 113 and 114. Accordingly, we can enforce the monitoring, recordkeeping and reporting requirements, which, as discussed under the first factor, are adequate to assure compliance with this NSPS. Also, states and the EPA often conduct voluntary compliance assistance, outreach and education programs (compliance assistance programs), which are not required by statute. We determined that these additional programs will supplement and enhance the success of compliance with these proposed standards. We believe that the statutory requirements for implementation and enforcement of this NSPS by the delegated states, the EPA and the additional assistance programs described above together are sufficient to assure compliance with these proposed standards without relying on title V permitting.
      Our balance of the four factors strongly supports a finding that title V is unnecessarily burdensome for the oil and gas non-major sources.   While title V might add additional compliance requirements if imposed, we believe that there would not be significant improvements to the compliance requirements in this proposed rule because the proposed rule requirements are specifically designed to assure compliance with the proposed NSPS and, as explained above, some of the title V requirements may not be appropriate for certain operations and/or proposed standards. We are also concerned with the potential burden that title V may impose on some of these sources. In light of little or no potential gain in compliance if title V were required, we do not believe that the costs of title V permitting is justified in this case. Finally, there are adequate implementation and enforcement programs in place to assure compliance with these proposed standards. Thus, we propose that title V permitting is "unnecessarily burdensome" for the oil and gas non-major sources.
      In addition to evaluating whether compliance with title V requirements is "unnecessarily burdensome," EPA also considered, consistent with guidance provided by the legislative history of section 502(a), whether exempting oil and gas NSPS non-major sources from title V requirements would adversely affect public health, welfare or the environment. The title V permit program does not impose new substantive air quality control requirements on sources, but instead requires that certain procedural measures be followed, particularly with respect to determining compliance with applicable requirements. As stated in our consideration of factor one, title V would not lead to significant improvements in the compliance requirements for the proposed NSPS. For the reason stated above, we believe that exempting these non-major sources from title V permitting requirements would not adversely affect public health, welfare or the environment.
      On the contrary, we are concerned that requiring title V in this case could potentially adversely affect public health, welfare or the environment. As mentioned above, we anticipate a significant increase in the number of permit applications that permitting authorities would have to process each year. Depending on the number of non-major sources that would be subject to this rule, requiring permits for those sources, at least in the first few years of implementation, could potentially adversely affect public health, welfare or the environment by shifting state agencies resources away from assuring compliance for major sources (which cannot be exempt from title V) to issuing new permits for these non-major sources, potentially reducing overall air program effectiveness.
      Based on the above analysis, we conclude that title V permitting would be "unnecessarily burdensome" for oil and gas NSPS non-major sources. We are, therefore, proposing that these non-major sources be exempt from title V permitting requirements.
VI. Rationale for Proposed Action for NSPS
A. What did we evaluate relative to NSPS?
	As noted above, there are two existing NSPS that address emissions from the Oil and Natural Gas source category. These NSPS are relatively narrow in scope, as they address emissions only at natural gas processing plants. Specifically, 40 CFR part 60, subpart KKK addresses VOC emissions from leaking equipment at onshore natural gas processing plants and 40 CFR part 60, subpart LLL addresses SO2 emissions from natural gas processing plants.
      CAA section 111(b)(1)(B) requires the EPA to review and revise, if appropriate, NSPS standards. Accordingly, we evaluated whether the existing NSPS reflect the BSER for the emission sources that they address. This review was conducted by examining currently used, new and emerging control systems and assessing whether they represent advances in emission reduction techniques from those upon which the existing NSPS are based, including advances in LDAR approaches and SO2 control at natural gas processing plants. For each new or emerging control option identified, we then evaluated emission reductions, costs, energy requirements and nonair quality impacts, such as solid waste generation.
      In this package, we have also evaluated whether there were additional pollutants emitted by facilities in the Oil and Natural Gas source category that warrant regulation and for which we have adequate information to promulgate standards of performance. Finally, we have identified additional processes in the Oil and Natural Gas source category for which it may be appropriate to develop performance standards. This would include processes that emit the currently regulated pollutants, VOC and SO2, as well as any additional pollutants for which we determined regulation to be appropriate.
B. What are the results of our evaluations and proposed actions relative to NSPS?
1. Do the existing NSPS reflect the BSER for sources covered?
	Consistent with our obligations under CAA section 111(b), we evaluated whether the control options reflected in the current NSPS for the Oil and Natural Gas source category still represent BSER. To evaluate the BSER options for equipment leaks, we reviewed EPA's current LDAR programs, the Reasonably Available Control Technology (RACT)/Best Available Control Technology (BACT)/Lowest Achievable Emission Rate (LAER) Clearinghouse (RBLC) database, and emerging technologies that have been identified by partners in the Natural Gas STAR program.
	The current NSPS for equipment leaks of VOC at natural gas processing plants (40 CFR part 60, subpart KKK) requires compliance with specific provisions of 40 CFR part 60, subpart VV, which is a LDAR program, based on the use of EPA Method 21 to identify equipment leaks. In addition to the subpart VV requirements, we reviewed the LDAR requirements in 40 CFR part 60, subpart VVa. This LDAR program is considered to be more stringent than the subpart VV requirements, because it has lower component leak threshold definitions and more frequent monitoring, in comparison to the subpart VV program. Furthermore, subpart VVa requires monitoring of connectors, while subpart VV does not. We also reviewed options based on optical gas imaging.
	As mentioned above, the currently required LDAR program for natural gas processing plants (40 CFR part 60, subpart KKK) is based on EPA Method 21, which requires the use of an organic vapor analyzer to monitor components and to measure the concentration of the emissions in identifying leaks. We recognize that there have been advancements in the use of optical gas imaging to detect leaks from these same types of components. These instruments do not yet provide a direct measure of leak concentrations. The instruments instead provide a measure of a leak relative to an instrument specific calibration point. Since the promulgation of 40 CFR part 60, subpart KKK (which requires Method 21 leak measurement monthly), the EPA has updated the 40 CFR part 60 General Provisions to allow the use of advanced leak detection tools, such as optical gas imaging and ultrasound equipment as an alternative to the LDAR protocol based on Method 21 leak measurements (see 40 CFR 60.18(g)). The alternative work practice allowing use of these advanced technologies includes a provision for conducting a Method 21-based LDAR check of the regulated equipment annually to verify good performance.
	In our review, we evaluated 4 options in considering BSER for VOC equipment leaks at natural gas processing plants. One option we evaluated consists of changing from a 40 CFR part 60, subpart VV-level program, which is what 40 CFR part 60, subpart KKK currently requires, to a 40 CFR part 60, subpart VVa program, which applies to new synthetic organic chemical plants after 2006. Subpart VVa lowers the leak definition for valves from 10,000 parts per million (ppm) to 500 ppm, and requires the monitoring of connectors. In our analysis of these impacts, we estimated that, for a typical natural gas processing plant, the incremental cost effectiveness of changing from the current subpart VV-level program to a subpart VVa-level program using Method 21 is $3,352 per ton of VOC reduction.
      In evaluating 40 CFR part 60, subpart VVa-level LDAR at processing plants, we also analyzed separately the individual types of components (valves, connectors, pressure relief devices and open-ended lines) to determine cost effectiveness for individual components. Detailed discussions of these component-by-component analyses are included in the TSD in the docket. Cost effectiveness ranged from $144 per ton of VOC (for valves) to $4,360 per ton of VOC (for connectors), with no change in requirements for pressure relief devices and open-ended lines.
	Another option we evaluated for gas processing plants was the use of optical gas imaging combined with an annual EPA Method 21 check (i.e., the alternative work practice for monitoring equipment for leaks at 40 CFR 60.18(g)). We had previously determined that the VOC reduction achieved by this combination of optical gas imaging and Method 21 would be equivalent to reductions achieved by the 40 CFR part 60, subpart VVa-level program. Based on that emission reduction level, we determined the cost effectiveness of this option to be $6,462 per ton of VOC reduction. This analysis is based on the facility purchasing an optical gas imaging system costing $85,000. However, we identified at least one manufacturer who rents the optical gas imaging systems. That manufacturer rents the optical gas imaging system for $3,950 per week. Using this rental cost in place of the purchase cost, the VOC cost effectiveness of the monthly optical gas imaging combined with annual Method 21 checks is $4,638 per ton of VOC reduction.	A third option we evaluated consisted of monthly optical gas imaging without an annual Method 21 check. We estimated the annual cost of the monthly optical gas imaging LDAR program to be $76,581, based on camera purchase, or $51,999, based on camera rental. However, because we were unable to estimate the VOC emissions achieved by an optical imaging program alone, we were unable to estimate the cost effectiveness of this option.
	Finally, we evaluated a fourth option similar to the third option, except that the optical gas imaging would be performed annually rather than monthly. For this option, we estimated the annual cost to be $43,851, based on camera purchase, or $18,479, based on camera rental.
	We request comment on the applicability of a LDAR program based solely on the use of optical gas imaging. Of most use to us would be information on the effectiveness of this and, potentially, other advanced measurement technologies, to detect and repair small leaks on the same order or smaller than specified in the 40 CFR part 60, subpart VVa equipment leak requirements and the effects of increased frequency of and associated leak detection, recording and repair practices.
	Because we could not estimate the cost effectiveness of options 3 and 4, we could not identify either of these two options as BSER for reducing VOC leaks at gas processing plants. Because options 1 and 2 have achieve equivalent VOC reduction and are both cost effective, we believe that both options 1 and 2 reflect BSER for LDAR for natural gas processing plants. As mentioned above, option 1 is the LDAR in 40 CFR part 60, subpart VVa and option 2 is the alternative work practice at 40 CFR 60.18(g) and is already available to use as an alternative to subpart VVa LDAR. Therefore, we propose that the NSPS for equipment leaks of VOC at gas processing plants be revised to require compliance with the subpart VVa equipment leak requirements.
	For 40 CFR part 60, subpart LLL, we reviewed control systems for SO2 emissions from sweetening units located at natural gas processing plants, including those followed by a sulfur recovery unit. Subpart LLL provides specific standards for SO2 emission reduction efficiency, on the basis of sulfur feed rate and the sulfur content of the natural gas.
	According to available literature, the most widely used process for converting H2S in acid gases (i.e., H2S and CO2) separated from natural gas by a sweetening process (such as amine treating) into elemental sulfur is the Claus process. Sulfur recovery efficiencies are higher with higher concentrations of H2S in the feed stream due to the thermodynamic equilibrium limitation of the Claus process. The Claus sulfur recovery unit produces elemental sulfur from H2S in a series of catalytic stages, recovering up to 97-percent recovery of the sulfur from the acid gas from the sweetening process. Further, sulfur recovery is accomplished by making process modifications or by employing a tail gas treatment process to convert the unconverted sulfur compounds from the Claus unit.